Is there really enough space to “put it back” Is there really enough space to “put it back”?  Capacity Estimation for Geologic Storage of CO2 Susan Hovorka, Srivatsan Lakshminarasimhan, JP Nicot Gulf Coast Carbon Center Bureau of Economic Geology Jackson School of Geosciences The University of Texas at Austin

Amount of CO2 to be sequestered 7 x 109T/year US emissions from stationary sources If spread evenly over US: 30 cm/year at @STP 0.4 mm/year at reservoir conditions Sources dot size proportional to emissions Sinks color proportional to thickness

Assessing CO2 Storage Capacity In Brine-bearing Formations Identify a porous and permeable rock volume in the subsurface …That is below underground sources of drinking water …and isolated from them and from escape to the atmosphere by one or more seals … and collect data on areal extent, thickness, porosity, and permeability that permit simple estimates of storage capacity for CO2 Introduction to screening for brine storage. This screening is done by literature search and examination of existing subsurface data such as well logs, well production, and seismic data How much? If preceding steps are favorable, proceed to additional steps, including matching to sources, estimating cost, permanence, and risk/uncertainly

Options for Estimating Capacity Total pore volume x Efficiency factor (E) Volume in structural and stratigraphic traps solubility trapped residual phase 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 (Vatsan) Displaced water as a limit on capacity (JP)

What do people want to know when they ask for storage capacity? How much will go in? Volumetric approach – current state of art A focus on the two phase region: where is the CO2?

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 Is it necessary to confine CO2 injection to trap? Structural closure

Reservoir Model Estimate Sweep Efficiency, Reservoir Volumetrics Fault planes Model reservoir parameters as for hydrocarbons Sand body architecture Petrophysics – porosity, residual water saturation Input heterogeneity model sweep efficiency Unique elements Rapid charge Outside of trap dissolution Porosity Sand/shale sequences

Efficiency in Terms of Use of Pore Volume – by-passed volume The plume imaged with cross –well seismic tomography is shown on the left. The RST log traces for the injection and observation wells are shown with the change in Sigma from pre-injection to maximum saturation shown in dark blue. The white line shows the seal that forms the top of the injection zone. The tomogram in this case shows CO2 breakthrough, although the attenuation in the plume is stronger than observed with wireline logs. The diagram on the right shows the modeled geometry of the plume. With the blue colors showing the predicted CO2 saturation. Comparison of the observed and predicted shows that heterogeneity is higher than modeled and more Co2 was retained near the injection well (buoyancy effects are appear to be strongly expressed than they are the model). CO2 Saturation Observed with Cross-well Seismic Tomography at Frio Tom Daley LBNL

Capacity: Dissolution of CO2 into Brine – 1yr 40 yr 930 yr 1330 yr 5 yr 130 yr Dissolution can be significant if fluid is mobile, but it is slow 30 yr 330 yr 2330 yr Jonathan Ennis-King, CSRIO Jonathan Ennis-King, CO2CRC

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 When CO2 moves, significant Co2 dissolves Yousif Kahraka USGS

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

Risk or Consequences Approach to Capacity How much will go in before unacceptable consequence occurs? Fluid spills? Depending on saturation that may be OK how about bucket breaks?

Capacity in a Geographically limited area Well density 1-4 5-10

Closed Volume – Maximum Capacity May be Pressure Determined

Injection capacity Depth of formation Injection pressure Pore volume of formation Size of formation Porosity Pressure gradient D H W L Vp = ΦV = ΦLWH

Injection Pressure and Depth Maximum injection pressure must be less than fracture pressure Fracture pressure estimated to linearly increase with depth of formation Fracture pressure in geo-pressure zone may increase non-linearly

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

Maximum CO2 injected (Vi) for Given Pore Volume (Vp) 10% porosity 20% porosity 30% porosity 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.

Effect of pore volume Both porosity and size of domain varied < 5% of pore volume occupied by CO2

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

Effect of permeability Permeability variation shows marginal effect, especially at low values

Effect of pressure gradient Ratio of injected to pore volume scales almost linearly with pressure gradient Scope for theory-based correlatory approach to estimating capacity

Pressure Limits on Capacity Single well – injection rate limited by fracture pressure Well field – injection rate limited by pressure interference Total Basin – injection volume limited by saline fluid displacement Role of geo-pressure

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

Open Hydrologic System

Confined/Unconfined Aquifers Specific Storage - Storativity Unconfined (or water table) aquifer: dewatering pore space Confined (artesian) aquifer: rock matrix and water volume expansion Specific storage is a measure of how much water can be released from storage All we know about production can be applied to injection (~) Domenico and Schwartz (1990)

Fluid Displacement From an Open Hydrologic System Neglect 2 phase-flow details away from the injection area Assume horizontal basin 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 College Station Well Field CO2 Injection From Dutton et al., 2003

Fate of a Pressure Pulse in a Confined Aquifer

Hydraulic Conductivity (ft/day) Storativity [-]

Year 2000 heads Year 2050 heads

Outcrop is Impacted Year 2050 drawdowns

Conclusions Looking at large volumes of CO2 storage in pore space previously filled only with brine, we examined four combinations of boundary condition and risk avoided: Structural or stratigraphic trap: CO2 spills out of trap Open  trap/volume: CO2 escapes from volume Hydrologically closed basin: mechanical or capillary entry pressure of seal is exceeded Hydrologically open basin: unacceptable displacement of brine

Hydrograph from J-17 Well, Ft. Sam Houston Graph shows water level oscillations from earthquake off west coast of Sumatra 9.0 magnitude on Richter Scale Groundwater levels oscillated for 1 ½ hours with total amplitude of 2.6 feet Quake occurred at 00:58 (UTC) on December 26 Courtesy of Geary Schindel Edwards Aquifer Authority