Design of CO 2 storage

Transcription

1 Design of CO 2 storage Martin J Blunt Department of Earth Science and Engineering, Imperial College London Imperial College Centre for Carbon Capture and Storage

2 Some numbers Current emissions are around 30 Gt CO 2 per year (8.5 Gt carbon). Say inject at 10 MPa and 40 o C density is 700 kgm -3. This is around 10 8 m 3 /day or around 650 million barrels per day. Current oil production is around 85 million barrels per day. Huge volumes so not likely to be the whole story, but could contribute 1-2 Gt carbon/yr. Costs: 1-2p/KWh for electricity for capture and storage; per tonne CO 2 removed Shackley and Gough, Could help fill the UK emissions gap in 2020.

3 Aquifer storage 100 km x 100 km

4 Storage in oil and gas reservoirs 100 km x 100 km

5 Trapping background How can you be sure that the CO 2 stays underground? Dissolution CO 2 dissolves in water 1,000-year timescales? Denser CO 2 -rich brine sinks Chemical reaction acid formed carbonate precipitation years Hydrodynamic Trapping Trapping by impermeable cap rocks Capillary Trapping host rock rapid (decades): CO 2 as pore-scale bubbles surrounded by water. Process can be designed: Juanes et al. (WRR, 2006); Qi et al. (IJGGC, 2009)

6 Spread of CO 2 is an inherently multi-scale process 170m 3200m 2280m Pore scale: Model flow through pores directly µm-mm Laboratory scale: Model flow using continuum approximation cm-m Field scale: Model flow using continuum approximation m-km

7 CO 2 trapping in sandstones (lab scale) Sandstones and now carbonates using the porous plate method. For CO 2 have novel stirred reactor to ensure equilibrium. Collaboration with Shell on experiment design and JOGMEC (Japan) on in situ scanning. No vertical segregation. CO2 100% % Sw 0% %

8 Pore-scale network modelling 3 mm Network extracted directly from 3D micro-ct image. How to assign contact angle during waterflooding? Yes, water-wet, but not completely wetting. Match average contact angle range of 30 o. Future work: simulation directly on images and reactive transport.

9 Oil trapping in sandstones and predictions Berea Clashach Stainton Network model predictions: 0 to 30 (dashed line) and 35 to 65 (solid line) Controlled by coordination number and aspect ratio.

10 Oil trapping and empirical models Land (dashed) Spiteri et al (solid) S nwi S nwr = Snwr = αsnwi βs 1+ S nwi max S nwr 1 S wc nwi Berea Clashach Stainton 10

11 CO 2 trapping 9 MPa and 70 o C: typical for depths of around 900m, but higher temperature to be away from critical point; 50 o C more typical and will also be used. Significant quantities of CO 2 trapped maximum residual saturation = 35.5%. S = αs β S 2 or oi oi Curve is predicted well (R 2 =0.97) by the Spiteri at al., 2008 correlation: Less trapping seen than in an oil-brine system at the same T & P. Spiteri, E., R. Juanes, M. J. Blunt, and F. Orr (2008), A New Model of Trapping and Relative Permeability Hysteresis for All Wettability Characteristics, SPEJ, 13(3),

12 Capillary pressure Dimensionless primary drainage capillary pressure same for oil-brine and CO 2 -brine and mercury injection (except connate water). CO 2 is non-wetting for drainage processes (migration and cap rock intrusion). ρgd is equivalent to J = 0.012

13 Pore-scale experiments Novel micro-flow design. Carbon fibre core holder.

14 Diamond synchrotron Multi-scale imaging project: 180 m - approved Nov 10 - total investment 10.5M - new investment 1.5M - permanent lab space Oxfordshire, UK, total investment (=phase 1+2) = 383M Phase 3 start is planned for 2011

15 Pore-scale trapping

16 Trapped clusters Clusters with power-law distribution of size

17 More clusters.

18 ID results at the field scale with trapping Dissolution front Chase brine front Advancing CO 2 front 0.7 fg f g Series1 S g 0.2 Trapped CO 2 Mobile CO f gi =0.85 fgi=0.85 S Sgi=0.26 = fgi=0.5 f = 0.5 Sgi=0.19 S = S g The CO 2 -phase fractional flow f g as a function of CO 2 (gas) saturation, S g Distance (m) Simulation Analytical solution Qi et al., SPE

19 Injection into a depleted oil field Mobile CO 2 front Advancing oil front Chase water front Sh 0.47 Mobile Oil Analytical Simulation Trapped CO 2 Mobile CO Distance (m) 1D S h profile where CO 2 and brine injection into residual oil at f ci = 0.5 for 1100 days and followed by 5 days of chase brine injection.

20 Design of CO 2 storage A case study on a highly heterogeneous field representative of an aquifer below the North Sea: Producer Injector Use chase water to trap CO 2 during injection 1D results are used to design a stable displacement Simulations are used to optimize trapping SPE 10 reservoir model, 1,200,000 grid cells (60X220X85), 7.8 Mt CO 2 injected. Qi et al., SPE

21 3D results for aquifer storage 20 years of water and CO 2 injection followed by 2 years of water injection in realistic geology 170m Z 170m Z 3200m X Y 2280m 3200m X Y 2280m Trapped CO 2 saturation Mobile CO 2 saturation 95% of CO 2 trapped after 4 years of water injection Qi et al., SPE

22 Storing CO 2 in oil fields 52 m Trapped CO 2 Injecting more water leads to enhanced trapping and more CO 2 storage. 366 m 670 m Mobile CO 2 52 m 366 m 670 m CO 2 volumetric fraction Cumulative Production (m 3 ) 8E+05 6E+05 4E+05 2E Oil production CO 2 production Time (days) Qi et al., SPE

23 Conclusions Carbon capture and storage is a key technology in our efforts to avoid dangerous climate change. If it is to make a difference, carbon capture and storage will deal with volumes of fluid similar to those currently handled by the oil industry. Yes, this is a major engineering challenge: it is difficult, but I think it can be done. We have addressed a major public concern: how to ensure that the injected CO 2 stays underground. Capillary trapping is an important mechanism to store CO 2 as an immobile phase. Our study showed that brine + CO 2 injection can trap more than 90% of the CO 2 injected.

24 Future work Better experimental determination of trapping, hysteresis and relative permeability supercritical carbon dioxide systems and carbonates. Coupling with dissolution and geochemistry. Study regional pressure response, injectivity and fracturing. Field tests.

25 Acknowledgements Many colleagues: Tara LaForce, Ran Qi (Chevron), Lynn Orr (Stanford), Jon Gibbins (Edinburgh) Experimental team: Branko Bijeljic, Stefan Iglauer, Christopher Pentland, Yukie Tanino, Rehab Al-Magharby Shell under the Grand Challenge on Clean Fossil Fuels Qatar Petroleum, Shell and the Qatar Science and Technology Park under the Qatar Carbonates and Carbon Storage Research Centre Imperial College Centre for Carbon Capture and Storage