Geologic Sequestration: the Big Picture Estimation of Storage Capacity or How Big is Big Enough

1. Geologic Sequestration: the Big Picture  Estimation of Storage Capacity or How Big is Big Enough Susan Hovorka, Srivatsan Lakshminarasimhan, JP Nicot Gulf Coast Carbon Center Bureau of Economic Geology Jackson School of Geosciences The University of Texas at Austin Presented to TXU Carbon Management Program IAP for CO2 Capture by Aqueous Absorption Semi-annual meeting, Pittsburg, May 7, 2007

2. Large Volumes in the SubsurfaceNETL National Atlas Estimate Saline Aquifers Coal 156 - 183 109 metric tons of CO2 Oil and gas reservoirs 92 109 metric tons of CO2 Space for 1,014 to 3,370 109 metric tons of CO2 http://www.netl.doe.gov/publications/carbon_seq/atlas/index.html

3. Amount of CO2 to be sequestered • 7 x 109 T/year US emissions anthropogenic CO2 • If spread evenly over US as CO2: 3 cm/year at @STP 0.04 mm/year at reservoir conditions 3.9 shown here Sources dot size proportional to emissions Sinks color proportional to thickness

4. Options for Estimating Capacity • Volumetric approach: Total pore volume x Efficiency factor (E) • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks – well fields, faults • Pressure limits as a limit on capacity • Displaced water as a limit on capacity Volumetric Risk-based

5. Volumetric Approach • How much will go in? • Volumetric approach – current state of art • A focus on the two phase region: where is the CO2?

6. Risk or Consequences Approach to Capacity • How much will go in before unacceptable consequence occurs?

7. Fluid Displacement as a Limit on Capacity • Rate of injection limited by displacement of one fluid by another • Unacceptable displacement of brine

8. Total Pore Volume • Total pore volume = volume of fluids presently in the rock = porosity x thickness x area. • Not all volume is usable: • Residual water • Minimum permeability cut off • Sweep efficiency • bypassing and buoyancy

9. Heterogeneity – Dominant Control on Volumetrics Structural closure

10. Reservoir heterogeneity – more important in injection than production 3-D Seismic Stratal Slice Ambrose (2000) 1000 ft

11. Stacked ClosureHigher volumessummed though multiple zones Cornelius Reservoir Markham No. Bay City No. field Tyler and Ambrose (1986)

12. A) Efficiency in Terms of Use of Pore Volume – by-passed volume By-passed volume CO2 Saturation Observed with Cross-well Seismic Tomography at Frio Tom Daley LBNL

13. Hypothesis Capacity is Related To Heterogeneity Low heterogeneity – dominated by buoyancy Just right heterogeneity Baffling maximizes capacity Seal High heterogeneity -poor injectivity Seal Capacity Seal Heterogeneity

14. Options for Estimating Capacity • Volumetric approach: Total pore volume x Efficiency factor (E) • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks – well fields, faults • Pressure limits as a limit on capacity • Displaced water as a limit on capacity

15. Capacity: Dissolution of CO2 into Brine – Volumetrically a big unknown 1yr 40 yr 930 yr 1330 yr 5 yr 130 yr 30 yr 330 yr 2330 yr Jonathan Ennis-King, CSRIO Jonathan Ennis-King, CO2CRC

16. Rapid Dissolution of CO2 in Field Test – a significant factor in reducing plume size Within 2 days, CO2 has dissolved into brine and pH falls, dissolving Fe and Mn Yousif Kahraka USGS

17. Options for Estimating Capacity • Volumetric approach: Total pore volume x Efficiency factor (E) • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks – well fields, faults • Pressure limits as a limit on capacity • Displaced water as a limit on capacity

18. Capacity in a Geographically limited area 1-4 Wells per Sq km 5-10 10-30 >30

19. Role of Risk: Traps available you assume faults sealing and/or well completions acceptable Structural closure

20. Do Not Need Structure to Limit Plume Size – Role of Kv/Kh Kv <<<Kh Kv <Kh Seal Seal Effective horizontal baffling layers limit vertical rise – avoid spread below seal Weak layering allows rapid vertical migration= Large spread beneath seal Kh= Horizontal permeability Kh = vertical permeability. Related to rock fabric, Interpreted from sedimentary depositional environment

21. Options for Estimating Capacity • Volumetric approach: Total pore volume x Efficiency factor (E) • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks – well fields, faults • Pressure limits as a limit on capacity • Displaced water as a limit on capacity

22. Nearly Closed Volume – Maximum Capacity May be Pressure Determined

23. Injection Pressure and Depth • Maximum injection pressure must be less than fracture pressure • Fracture pressure estimated to linearly increase with depth of formation • Volume injected below fracture pressure increases with depth

24. Maximum CO2 injected (Vi) for Given Pore Volume (Vp) • Closed domain at several porosities and several different sizes leading to a range of brine-filed volumes Homogeneous geological formation, dimensions 10,000 ft x 10,000 ft x 1000 ft, and permeability 10 md, depth 7000 ft. Maximum pressure set at 75% lithostatic. 10% porosity 20% porosity 30% porosity

25. Effect of Depth of formation • Effect of the depth of formation almost entirely due to that of injection pressure

26. Effect of pore volume (contd) • Best fit over entire data suggest linear (blue) scaling • Ratio of injected to pore volume is about 1.5 % Vi = 0.01481 Vp

27. Options for Estimating Capacity • Volumetric approach: Total pore volume x Efficiency factor (E) • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks – well fields, faults • Pressure limits as a limit on capacity • Displaced water as a limit on capacity

28. Open Hydrologic System

29. Fluid Displacement From an Open Hydrologic System Output of an analytical model. Total means across the boundaries Vb1 and Vb2. Note: vertical axes are approximately equivalent (500 tons of CO2 is 500 t / 0.6 t/ m3 = 833 m3 of displaced water)

30. Carrizo-Wilcox System in Central Texas College Station Well Field CO2 Injection From Dutton et al., 2003

31. Fate of a Pressure Pulse in a Confined Aquifer

32. Year 2000 heads Year 2050 heads

33. Conclusions • Volumetric approach: DOE assessment shows more than adequate space • Free CO2 volume in structural and stratigraphic traps • Trapped CO2 residual phase • Volume dissolved – Significance and rate uncertain • Volume that can be stored beneath an area constrained by surface uses or by other unacceptable risks - What are key risks? • Pressure limits as a limit on capacity – Similar volume to that used in volumetric approach 1.5 % of pore volume useful, increases with depth • Displaced water as a limit on capacity – minor in large basins