1. Geologic CO2 Sequestration
Ian Duncan
Bureau of Economic Geology
University of Texas at Austin

2. Reduce Dispose Use CO2 MITIGATION OPTIONS Energy Efficiency
New Technology
Fuel Choice
Stop Leaks & Flares
Venting
Saline Aquifers
Depleted Reservoirs
Coal Beds
Deep Ocean
EOR
EGR
ECBM
Agriculture
Forests
Chemicals

3. INTRODUCTION Where to put CO2 Permanence? How long? Risk? How safe?
Implementation? How fast?
At what cost?

4. What can we do with CO2? CO2 Enhanced Oil Recovery (EOR)
CO2 Injection in Gas Fields for Pressure Maintenance and Sequestration
CO2 sequestration in deep brine reservoirs
CO2 sequestration in unmineable coal

5. INTRODUCTION Properties of CO2 Trapping Mechanisms CO2 Pilot Projects
CO2-EOR

6. CO2 SEQUESTRATION in DEEP BRINE RESERVOIRS
CO2 is captured, compressed, pipelined, and injected into deep brine reservoirs over a mile beneath the surface
This is a new technology based on experience in CO2 EOR.

7. CO2 Properties IPCC Report
CO2 properties: density increases with pressure and decreases with Ture. P and T increases with depth usual result is increased density with depth
T=31.3C – P=73.9bar

8. Trapping mechanisms Structural Trapping Capillary Trapping
CO2gas + H2O  H2CO3o
H2CO3o  HCO3- + H+
Dissolution Trapping
Mineral Trapping
Ca++ + HCO3-  H+ + CaCO3
Fe++ + HCO3-  H+ + FeCO3
(sorption)
Solubility in water: increase with increasing pressure and decreases with increasing temperature and salinity.
Solubility in oil: ~x10 that into water + miscibility in certain conditions pf P, T and oil type (light to medium)
Markham North - Bay City North field
Modified from Tyler and Ambrose (1984)

9. Trapping mechanisms Structural Trapping Capillary Trapping
Dissolution Trapping
Mineral Trapping
(sorption)
Solubility in water: increase with increasing pressure and decreases with increasing temperature and salinity.
Solubility in oil: ~x10 that into water + miscibility in certain conditions pf P, T and oil type (light to medium)
Markham North - Bay City North field
Modified from Tyler and Ambrose (1984)

10. KEY ISSUES For CO2 SEQUESTRATION in DEEP BRINE RESERVOIRS
Scientific Issues: reservoir geology; fault/shale seal leakage; Monitoring/Measurement/Verification
Engineering Issues: Injection rate; cement seal lifetime; blowout prevention
Policy Legal Issues: regulation; performance standards; who owns pore space?; long term liability

11. Bureau of Economic Geology’s FRIO Pilot Injection Site
Thank you for the opportunity to see the results of your most interesting experiment and exchange information on the results of the Frio experiment. I hope that this comparison will be lead to better understanding of both experiments
Research Funded by
DOE NETL and Gulf Coast carbon Center

12. Frio Experiment: Monitoring CO2 Storage in Brine-Bearing Formations
Testing Ability to Predict and Monitor Sequestration
(1) high-quality characterization prior to injection
(2) numerical modeling integrated with all phases of the project
(3) cross-comparison of multiple types of measurements
(4) use of wireline logs for monitoring plume movement
(5) above-zone monitoring for leakage, and
(6) traditional groundwater monitoring for leakage.
Our DOE program manager defined the project goal. The project team defined the list of four achievable goals (read)

13. Site Search Site Power plants Refineries Sedimentary cover> 6km
The experiment site was selected following a national review of prospective brine formation sites for CO2 storage. Blue colors show areas of adequately thick sedimentary rocks. Green dots show location and volumes of emissions from power plants, and red dots show refineries and chemical plants. {animation} We selected the Gulf coast as an area with a large number of sources, including some that can serve as a source for the pilot, and large volume of sediments.
{animation]. In the next side we will see a cross section along the yellow line
Power plants
Refineries
Sedimentary cover> 6km
Sources: USGS, IEA Source database

14. Frio Brine Pilot Site Injection interval Oil production
Injection interval: 24-m-thick, mineralogically complex Oligocene reworked fluvial sandstone, porosity 24%, Permeability 2.5 Darcys
Unusually homogeneous
Steeply dipping 16 degrees
7m perforated zone
Seals  numerous thick shales, small fault block
Depth 1,500 m
Brine-rock system, no hydrocarbons
150 bar, 53 degrees C, supercritical CO2
Injection
interval
This true-scale block diagram shows the geologic chrematistics of the site. Oil production is from the deeper zone. Our experimental interval is brine with no free methane or oil. I will bring to your attention the high permeability 2. 5 Darcies, in contrast to the Nagaoka site. [animation] The next side will show detail in the injection zone
Oil production

15. Frio 1 Pilot: Cross-Comparison of Multiple Types of Measurements
Determine the subsurface distribution of injected CO2 using diverse monitoring technologies
Aquifer wells (4)
Gas
wells
Access tubes, gas sampling
Downhole
P&T
Downhole sampling
U-tube
Gas lift
The major elements of the monitoring program are based on the two-well system: an injection well and observation well completed in the injection zone where the CO2 plume is shown in orange. (animations) downhole pressure and temperature, azmuthal VSP, cross well seismic, EM, wireline logging, downhole sampling with a kuster sampler, the U-tube, and gas lift, and a suite of applied tracers (PFT’s, noble gasses, SF6). The program was less frequent than at Nagaoka, with 6 well logging and two seismic data collections.
Wireline
logging
Radial VSP
Cross well Seismic, EM
Tracers

16. Observation Well Injection Well Closely spaced measurements
in time and space
The injection and monitoring wells are 30 m apart in the injection zone. The CO2 came from cold liquid storage tanks, though the heater and compression truck, past the tracer injection ports, onto the well head and down to Frio sandstone at 1500 m though tubing. At this depth it spread radially. We have one subsurface observation point at the retrofit production well in the foreground. From this well we extract small volume samples though the “U” tube and measure pressure, and temperature down hole as well as what you can see at surface.

17. New tool to do the job: LBNL U-tube instrument to collect high frequency, high quality two-phase samples
The U-tube was designed by Barry Friefeld, LBNL, to exact minimally contaminated and minimally fractionated samples from the reservoir zone at surface. Here you see the aqueous chemists collecting fluids. Gas analysis was done in-line inside the portable lab.
Tommy Phelps
Dave Ristenburg
Oak Ridge National Lab
Seay Nance
BEG

18. Elapsed hours after injection
Fluid Evolution During injection- Dissolution of CO2 and Rock-Water interaction
CO2 breakthrough pH
The U-tube was designed by Barry Friefeld, LBNL, to exact minimally contaminated and minimally fractionated samples from the reservoir zone at surface. Here you see the aqueous chemists collecting fluids. Gas analysis was done in-line inside the portable lab.
Elapsed hours after injection

19. CO2 Saturation Observed with Cross-well Seismic Tomography vs. Modeled
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).
Tom Daley and Christine Doughty LBNL

20. COSTS FOR CARBON CAPTURE AND STORAGE 1) CO2 Capture 2) Compression and Transport 3) Injection and Storage 4) Monitoring and Mitigation

21. COST ESTIMATES FOR CARBON CAPTURE AND STORAGE Publicly available information gives a qualitative indication of costs, however these estimates must be treated with caution. Published estimates typically do not reveal assumed energy costs or steel prices

22. CAPTURE OF CO2 Pre- Versus Post- Combustion CO2 Capture

23. Solids and Co-products
Combustion Turbine
FutureGen
IGCC w/ CO2 Capture
Steam
Syngas
Coal
Petroleum Coke
Refinery Co-products
Gasifier
Oxygen
Modified from Eastman Chemical
Slag/Soot
Electricity
SteamTurbine
Steam
Shift Reactor
Hydrogen H
CO2
Particulate Removal
CO2
Sulfur
Sulfur
Solids and Co-products

26. CO2 CAPTURE COST VS. POWER PLANT TYPE Integrated gasification
100 80
Natural gas combined cycle (NGCC)
Natural gas boiler (NGB) 60
Capture costs ($/ton)
Coal boiler (PC) 40 20
Integrated gasification
combined cycle (IGCC)
IEA GHG, 2002
Praxair unpublished data
Professor Gary Rochelle, UT, unpublished data) 10 20 30 40 50
CO2 content of flue gas (%)
QAd6067

27. “Adjusted” CO2 CAPTURE COSTS Integrated gasification
100 80
Natural gas boiler (NGB) 60
Capture costs ($/ton)
Coal boiler (PC) 40
Natural gas combined cycle (NGCC)
Integrated gasification
combined cycle (IGCC) 20
IEA GHG, 2002
Praxair unpublished data
Professor Gary Rochelle, UT, unpublished data) 10 20 30 40 50
CO2 content of flue gas (%)
QAd6067

28. Compression Costs
Current EOR Industry Compression….. Second largest cost… approximately $8 to 10?? per metric ton or higher
Compression costs higher at smaller scale. Above cost estimates for millions of metric tons a year scale.

29. Compression Costs
Compressor cost estimates typically based on natural gas prices
At US $4 /GJ for natural gas, energy is less than one third of compression costs over 25 years
At US $12 /GJ for natural gas, energy is over two thirds of compression costs over 25 years

30. Need membrane separation of Hydrogen from CO2 at pressure.
Compression Costs
Key point for CCS…. Gasification can produce high pressure CO2 streams but current commercial technology depressures gas for clean up.
Need membrane separation of Hydrogen from CO2 at pressure.

31. Estimates for Pipeline Transportation Costs…..
$1-10/metric tons per 100 km (EIA, 2006)
6% of compression costs per 100 Km (MHI, 2002)

32. Monitoring, cost estimates: 10 to 50 cents per metric ton
Monitoring Costs
Monitoring, cost estimates: 10 to 50 cents per metric ton

33. What about role of CO2 in Enhanced Oil Recovery
(CO2-EOR)?

34. CCS Costs and EOR
Carbon capture and storage is expensive
Texas and the Gulf Coast may where CCS starts first because CO2 EOR can be used to jump start developing a sequestration industry
Texas and the Gulf Coast could become the low-cost provider for sequestration
80% of CO2 EOR in the world takes place in Permian Basin of Texas…. Texas companies can leverage this expertise

35. United States CO2 EOR
2 Bcf/day (~35 MMTY) of CO2 currently injected for EOR, largely in the Permian Basin
~ 20% of CO2 for EOR is anthropogenic (~ 7 MMTY)
Annual U.S. oil consumption is ~7 BSTB and annual oil production is ~3.2 BSTB
Current U.S. CO2 EOR Production ~ 206 MBOPD, 7.5 MMBOPY
4% of U.S. production, 66 active projects, 50 in Permian Basin

36. CO2 Injection

37. 1,500 psi – Miscibility Between Gas and Oil Begins to Develop
A clear Middle Phase forms and spreads between the oil and gas.  The interfacial tensions are very low.  Oil recovery will be high and the displacement will appear to be above the Minimum Miscibility Pressure (MMP).

38. 2,500 psig – CO2 Has Developed Miscibility with the Oil
Well above the MMP - The miscible fluid is the very light fluid flowing in a channel past the darker bypassed oil.   The miscible fluid is Extracting NGL  from the bypassed oil .  First, the fluid gets lighter, then -

39. Oil Displacement by Miscible CO2
Lynn Orr, Stanford

41. The Track Record CO2 Enhanced Oil Recovery
In the US
~ 30 million metric tons of CO2 are injected annually in the Permian Basin over 13,000 EOR wells over 3600 miles of CO2 pipelines over 600 million tons of CO2 transported in total approximately 1.2 billion metric tons of CO2 injected

42. CO2 Enhanced Oil Recovery
Injection at SACROC Oil Field in Scurry County since SACROC currently injects ~13.5 MMt CO2/yr recycles ~7 MMt CO2/yr net storage of ~6.5 MMt CO2/yr.

43. CURRENT INJECTION PROJECTS
25,000
Acid-gas
injection
Sequestration projects
EOR
20,000
15,000
CO2 injected (tonnes/day)
500 MW coal plant
10,000
5,000
Statoil
(Sleipner)
Encana
(Weyburn)
(Seminole)
Wasson) ) UT
(Frio Brine)
Statoil
(Snohvt BP
(In Sallah)
Chevron
(Rangeley)
Kinder
Morgan
(Sacroc)

44. A Scenario for Implementation of Carbon Sequestration in the Gulf Coast

45. Potential Gulf Coast CO2 EOR Reservoirs

46. Geologic Storage in the Gulf Coast
CO2 capture.
CO2 will be used for EOR
to offset development cost and
speed implementation.
Oil
Very large volume
Of CO2 storage potential
in brine formations beneath
reservoir footprints
Brine
Gulf Coast Carbon Center

47. Miscible CO2 EOR Potential of Gulf Coast
Volumes of additional oil that are a target for CO2 EOR is nearly 5 billion.
Mark Holtz, GCCC

48. CO2 EOR Is not “The Answer” …
Limits on usefulness of EOR

49. …but CO2 EOR is a great beginning
Economic or near economic in current market, depending on cost of CO2
Acceptable to public
Other major benefits (domestic energy production, taxes, employment)
Build infrastructure that can be used long term for large volume CO2 disposal = stacked storage
Advantages of EOR

50. What about Risk?

51. Risk = Likelihood x Consequences

52. Individual Risk = Likelihood x 1 death

53. EXAMPLES OF INDIVUAL RISKS: North Sea offshore oil and gas production 1 in 1000 or 1 x 10-3 per year. Equivalent to a rate of just above 30 fatal accidents per 108 exposure hours. Mountain climbing: risk of 10-3 per year Driving an automobile: risk of 1 x 10-4 per year Flying: risk of 5 x 10-5 per year.

54. How do you evaluate the risks associated with something that has never been done before?

55. Can we use Natural Gas Pipeline Data …
Can we use Natural Gas Pipeline Data …. to Understand Likelihood of failure of Future CO2 Pipelines?

56. Natural Gas Pipeline Incident Rates used by Published CO2 Pipeline Risk Analyses
3.0 × 10-3 to 1.5 × 10-4 (per kilometer per year), median of about 2.0 × published CO2 pipeline risk analyses use these probability estimates

57. Natural Gas Transmission Pipeline Incidents

58. But Pipelines are Getting Safer!

59. Pipeline Deaths and Injuries
( )

60. Fatality and Injury Rates Natural Gas Transmission Pipelines

61. Injury + Fatality Rates versus Number of Significant Incidents

62. Public versus Non-Public Risks
Public fatality risk = 7.2 x 10-7 Non-Public fatality risk = 4.8 x 10-7

64. Serious Incident Rate versus Gas Price

65. Injury and Fatality Rate Versus NG Pipeline Age

66. Public versus Company Injury/Fatality Rates

68. Pipeline Wall Thickness Versus Diameter

69. High Consequence Areas
Class 1 Rural 10 or fewer houses within 150 meters Class 2 Village or outer suburban area with more than 10 and less than 46 buildings intended for human occupancy within 150 meters. Class 3 Town with 46 or more houses or any area within 100 meters of a building or a playground, recreation area, outdoor theatre, etc. Class 4 Urban/city buildings with four or more stories

70. Design Factors for HCAs
ASME B31.8S specified minimum yield strength (SMYS) as key design factors: Class 1 72% of SMYS Class 2 60% of SMYS Class 3 50% of SMYS Class 4 40% of SMYS For constant pipeline pressure, the design factor is accommodated by increasing the wall thickness thus increasing the SMYS

71. Public Fatality Rate

72. Safety Factor vs. Rupture (>10 in) Rate

73. CONCLUSIONS: CO2 Pipeline Risk
Likelihood of CO2 pipeline failure significant enough to cause deaths at least 3 orders of magnitude less than assumed in previous risk studies.
Individual risk of CO2 pipelines is likely 10-7 or lower
Fatality risk of a well designed, appropriately mitigated CO2 pipeline in an urban area is even lower

74. RECAP… DISCUSSION Where to put CO2 Permanence? How long?
Risk? How safe?
Implementation? How fast?
At what cost?

75. Thanks!
For more information: