Predicting the fate of CO2 in

geological reservoirs. Mike Bickle,

(Earth Sciences & DAMPT,

Cambridge)

Nelly Assayag, John Becker,

Fran Boait, Hazel Chapman, Andy

Chawick, Benoit Dubacq, Herbert

Huppert, Niko Kampman, Sarah Lyle,

Alex Maskell, Jerome Neufeld, Nicky

White, Max Wigley, Andy Woods

&

the CRIUS Consortium

(Cambridge, Manchester, Leeds,

British Geological Survey)

What actually happens? What have we learnt? How should we go about learning more?

Modelling – calculations - Numerical

- Analytical (physics)

- Laboratory tank

Field tests - Remote imaging

(small scale, full scale) - Downhole logging

- Sampling fluids

Geological analogues - Long time frames

- Demonstrate long-term

safety

Crystal

Geyser

CO2

Reservoir

penetrated

by

exploration

well

Bleached sandstones – fossil CO2 reservoirs?

Bleached sandstones: Possible fossil CO2-rich brines?

Use as analogue for processes in CO2 storage reservoirs

Isopach

map of

the

Utsira

sand.

Sleipner – separated from natural gas on

platform,

Re-injecting CO2 at 1 million tons/year:

Started in 1996,

Monitored by 3D seismic surveys in 1999,

2001, 2002, 2004, 2006 & 2008.

1994 (injection started 1996) 1999 1999

Why model:

enable predictions – need to verify,

test assumptions and inputs.

seismic

imaging

~ 33 m

resolution

not < 8 m

Modelling ignores flow of

saline fluid velocity u, constant with

depth.

Lyle et al., 2005, J. Fluid. Mech.

Axisymmetric

Tank experiments

Tank experiments: normalised radius

Profile just stretches

Tank experiments: Waterton 4th yr project 2012

Salt Creek: 3He & 129Xe spike injection 2010

CO2 dissolution and fluid-mineral reactions:

An experiment on an Enhanced Oil Recovery phase.

Shallow Low Temperatures Challenges

1

Water/CO2 Water/CO2

2

3

Oil Oil

1 Injection Pressure Limit

CO2 Override 2

Unfavorable Mobility Ratio 3

•Unable to attain MMP conditions under conventional operations

•Low CO2 Density and Reduced Flood Front Velocity Promotes

Gravity Override

•Low CO2 Viscosity Magnifies Volumetric Sweep Challenge

How do we design a flood to best address these challenges?

Injection Experiment at

an Oil Field using CO2 for

enhanced oil recovery

Field has long and

complex history of water

injection for oil recovery

Progressive injection of

CO2 and re-injection of

produced water

Seismic reflection images:

O’Brian et al., 2010, The Leading Edge

Injection started here April 2008

Formation dips ~ 7° east

Dear diary,

Today the weather was nice and

warm but quite windy. We have

sampled 30 28 16 18 14 and filtered

and titrated everything. Filtering

and titrating is great fun and not

boring at all. I wish I could do that

all the time, and when I grow up I

want to be a chemist.

Water samples

-Separating oil

Water Chemistry: Mineral dissolution

Complex

history of

water

flooding,

injection of

water prior

to injection

of CO2

Well 18

Open symbols –

injection water

Note CO2 front ( 32 days) earlier

than anion fronts or d18O front

Injection waters arrive between

50 & 80 days?

Calculate fluid-mineral reactions from change in water chemistry

Plagioclase dissolution rate: ~ 5x10-14 mol/m2/s

Calculated reaction path: Calcite or Calcite + Plagioclase + Kspar – Sm - Qtz

CO2 solubility at 80 bars ~ 1.2 mole/L

Alkalinity at surface ~ 0.1 mole/L

Implies degassing in production well

Diffusion distance for CO2 into brine in 150 days is about 30 cm:

Can enough CO2 dissolve?

Sandstones: heterogeneous

and reactive

What is permeability structure of reservoir?

On what scale does CO2 finger? Wall Creek II

Flow of pure CO2 – 200 mD, 200 m, DP = 7 MPa

200 m in 4 days

Flow of CO2 displacing water:

200 m in 25 days

Model CO2 – brine movement with simple 1D model –Ask:

1) What is age and age distribution of water?

2) How much CO2 dissolves from CO2 adjacent to brine?

3) What is average CO2 content of produced water? Model flow 1D, constant pressure differential, injected fluid viscosity 1/10th, sharp interface,

ignore cross-layer flow!

CO2 Flux?

Water ages – young, waters mixed

Conclusions:

1) Need to know flow paths to model CO2 dissolution

rates.

2) Need to know mineral reaction rates – especially

carbonate dissolution in field settings:

3) Carbonate dissolution may increase permeabilities

significantly.

Would be good to learn more about flow of CO2.

Fluid-fluid and mineral fluid reactions are surprisingly fast.

Need field injection experiments to understand controlling

small scale processes.