1. 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

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

3. 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

4. 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)

5. 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?

6. 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

7. Heterogeneity – Dominant Control on Volumetrics
Is it necessary to confine CO2 injection to trap?
Structural closure

8. 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

9. 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

10. 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

11. 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

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

13. 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?

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

15. Closed Volume – Maximum Capacity May be Pressure Determined

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

17. 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

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

19. 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.

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

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

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

23. 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

24. 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

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

26. Open Hydrologic System

27. 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)

28. 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)

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

30. Fate of a Pressure Pulse in a Confined Aquifer

31. Hydraulic
Conductivity
(ft/day)
Storativity
[-]

32. Year 2000
heads
Year 2050
heads

33. Outcrop is Impacted
Year 2050 drawdowns

34. 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

35. 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