CO2 Geological Storage –Migration Processes and Pathways

Karsten Michael

CSIRO ENERGY

IEAGHG Summer School, Perth, Australia6-11 December 2015

Potential impacts of CO2 injection

The subsurface area, as projected to surface, beyond the physical presence of CO2, but in which reservoir pressures are above ambient conditions. Pressures decrease rapidly outward along with the potential to drive unwanted migration or impact other resources. This area would require targeted characterisation and monitoring of identified potential leakage conduits (i.e. faults, old wells).

SURFACE PROJECTION OF CO2 PLUMEThe subsurface area, as projected to the surface, in which CO2 is present as a physically distinct phase. Within this footprint, reservoir pressures are highest and may be sufficient to drive lateral or vertical migration of CO2 and brine. This area requires the highest standard regarding site characterisation, monitoring and consideration of remediation options.

SURFACE PROJECTION OF INCREASED PRESSURE

Potential migration pathways

Two-phase flow

• Interplay between 3 forces:• Viscous force (injection pressure, formation water flow: Darcy’s Law)

• Buoyancy (density difference between 2 fluids, vertical)

• Capillarity (pore throat radius, interfacial tension, wettability)

• Capillary number represents the relative effect of viscous forces versus surface tension:• Ca = dynamic viscosity x flow velocity / interfacial tension

• Flow is dominated by capillarity if Ca < 10-5

• Drainage & imbibition• Capillary entry pressure

• Relative permeability, residual saturation

• Hysteresis

CO2 injection

Bk

qtktr

rwc

wrc

CO

)(

2

k = permeability = viscosityq = injection volume = porosityB = thickness

Nordbotten et al., 2005

Post-injection

Szulczeski et al., 2012

buoyancyr

rrCO2

r

rFFF +

-+-

0

w

w0

w zHg

CO2

*

Pressure-related force component

buoyancyr

rrCO2

r F-

- Egw

w

w

00CO2 F- Hgr

Hydrodynamic impact on CO2 migration

q = F* k

r

r rCO2-

w

w

Tilt factor:

CO2-water tilt: 0H

r

r rCO2-

w

w

Effect of flow on CO2 trapping

Single fluid

Two fluids (say oil and water)

Effective permeabilities ko kw

Relative permeabilities kro krw

dx

dpkAq

w

w

-

.

,

dx

dpAkq

dx

dpAkq

w

w

w

o

o

o

-

-

,

,

kkk

kkk

rww

roo

Darcy’s Law

Residual trapping

Capillary pressure & relative permeability

Relative permeability depends on capillary pressure so hysteresis in Pc

results in different kr curves for imbibition and drainage

Sw

kr

Drainage

Imbibition

Irreducible water

saturationResidual CO2

saturation

Aquifer geometry

Aquifer fabric

Boundary conditions

Injectivity – Number of injectors

1.1 Mt/year

Total: 22 Mt

0.37 Mt/year per well

1.85 Mt/year

Total: 37 Mt

0.25 Mt/year per well

2.0 Mt/year

Total: 40 Mt

V = 72 km3

Porosity = 20%CO2 density = 570 kg/m3

E = 2 %Capacity = 160 MtCO2

Fracture pressure = 150 bar

0.8 Mt/year per well

6.4 Mt/year

Total: 128 Mt (open boundaries)

Regional context

Long-range migration – basin-scale simulations

Meckel et al., 2015

Inversion percolation

Long-range migration – basin-scale simulations

Gibson-Poole et al., 2008

Geoscience Victoria

Long-range migration – basin-scale simulations

Assessment scale

Pore-scale

Core-scale

Well-scale

Reservoir-scale

Blunt et al., 2013

2 mm

Pore-scale imaging & modelling

20 cmCore-flooding

Well tests & logging

Production tests & model calibration

~100 m

Drill stem testing

20 km

Top seal leakage

Goldie-Divko et al., 2010

Well leakage

Gasda et al., 2004

Fault leakage

Bouvier et al., 1989; Lindsay et al., 1993

A) Across-fault

B) Up-fault

Ciftci et al., 2012

Potential impacts

Summary

• CO2 storage system has many similarities to the petroleum system Reservoir-seal terminology; migration pathways

Main differences: CO2 is highly soluble in formation water; assessment of potential migration out of the reservoir

• CO2 migration occurs due to the interplay of viscous forces, buoyancy & capillarity Viscous forces dominate near the well and during injection; buoyancy and

capillarity take over after injection has ceased and in the far-field

Choice of modelling method: analytical, numerical (Darcy, inver. percol.)

• Need to consider lateral migration within injection interval versus vertical migration (leakage) permeable faults, poorly completed wells, fracture systems in seal

displacement of formation water

• (Relative) permeability is a key parameter governing migration How is permeability measured? What scale?

What is the assessment (model) scale?