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

Large Volumes in the Subsurface NETL National Atlas Estimate Space for 1,014 to 3, metric tons of CO 2 Saline AquifersCoal metric tons of CO metric tons of CO 2 Oil and gas reservoirs

Amount of CO 2 to be sequestered 7 x 10 9 T/year US emissions anthropogenic CO 2 If spread evenly over US as CO 2 : 3 cm/year 0.04 mm/year at reservoir conditions Sources dot size proportional to emissions Sinks color proportional to thickness 3.9 shown here

Options for Estimating Capacity Volumetric approach: Total pore volume x Efficiency factor (E) –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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

Volumetric Approach How much will go in? –Volumetric approach – current state of art –A focus on the two phase region: where is the CO 2 ?

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

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

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

Heterogeneity – Dominant Control on Volumetrics Structural closure

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

Cornelius Reservoir Markham No. Bay City No. field Tyler and Ambrose (1986) Stacked Closure Higher volumes summed though multiple zones

Efficiency in Terms of Use of Pore Volume – by-passed volume A) Tom Daley LBNL CO 2 Saturation Observed with Cross-well Seismic Tomography at Frio By-passed volume

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

Options for Estimating Capacity Volumetric approach: Total pore volume x Efficiency factor (E) –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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

Capacity: Dissolution of CO 2 into Brine – Volumetrically a big unknown 1yr 5 yr 30 yr 40 yr 130 yr 330 yr 930 yr 1330 yr 2330 yr Jonathan Ennis-King, CO2CRC Jonathan Ennis-King, CSRIO

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

Options for Estimating Capacity Volumetric approach: Total pore volume x Efficiency factor (E) –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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

Capacity in a Geographically limited area >30 Wells per Sq km

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

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

Options for Estimating Capacity Volumetric approach: Total pore volume x Efficiency factor (E) –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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

Nearly Closed Volume – Maximum Capacity May be Pressure Determined

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

Maximum CO 2 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

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

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 = Vp

Options for Estimating Capacity Volumetric approach: Total pore volume x Efficiency factor (E) –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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

Open Hydrologic System

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)

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

Fate of a Pressure Pulse in a Confined Aquifer

Year 2000 heads Year 2050 heads

Conclusions Volumetric approach: DOE assessment shows more than adequate space –Free CO 2 volume in structural and stratigraphic traps –Trapped CO 2 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