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Addressing Climate Change through Carbon Capture and Geological Sequestration in Michigan Dave Barnes We Can Do It Here! 2009 Mid-America Regulatory Conference.

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Presentation on theme: "Addressing Climate Change through Carbon Capture and Geological Sequestration in Michigan Dave Barnes We Can Do It Here! 2009 Mid-America Regulatory Conference."— Presentation transcript:

1 Addressing Climate Change through Carbon Capture and Geological Sequestration in Michigan Dave Barnes We Can Do It Here! 2009 Mid-America Regulatory Conference June 15, 2009

2 2 The Dance of the 3 E’s (with a nod to Scott Tinker, TBEG)

3 3 US Energy Flow, 2007 (Quadrillion BTU’s, Quads) From: US – Energy Information Agency (EIA) 2007

4 4 } Efforts To Cap Near-term (<100 Years) Atmospheric CO ppmv Green House Gas Emissions and Energy-Technology Enabling Systems The Silver Buckshot

5 Governor Jennifer Granholm’s State of the State Address, Feb 3, 2009 “So here’s our next aggressive goal: By the year 2020, Michigan will reduce our reliance on fossil fuels for generating electricity by 45 percent. We will do it through increased renewable energy, gains in energy efficiency and other new technologies. You heard me right: a 45 percent reduction by 2020.” “How will we reach this 45-by-20 goal and get the jobs that come with it? Instead of spending nearly $2 billion a year importing coal or natural gas from other states we’ll be spending our energy dollars on Michigan wind turbines, Michigan solar panels, Michigan energy-efficiency devices, all designed, manufactured and installed by...Michigan workers.”

6 The New Energy Economy – US Energy Systems The goal of rapidly transforming US Fossil Fuel Intensive energy infrastructure to a low/no GHG emissions infrastructure is a formidable challenge 2007 EIA

7 Electric Power Consumption of Coal by Region, 2008 U.S. Total = 1,041.6 (-0.3%) Million Short Tons (Percent Change from 2007)

8 Michigan Electric Power Generation, by fuel Wind Power in Michigan

9 9 Carbon Capture and Storage, CCS CCS is various methods for capturing and permanently storing anthropogenic CO 2 that would otherwise contribute to global climate change. Global Carbon Cycle (Billion Metric Tons, Gt, Carbon)

10 10 Geological Sequestration (GS) Geological media suitable for storage of CO 2 in Michigan –depleted oil reservoirs (+/- CO 2 /EOR) and –deep, saline (brine-filled) reservoir formations ` ` CO 2 CRC

11 11 Michigan’s Deep GS Injection Zones As much as 16,000ft of bedrock sedimentary strata (below glacial drift) “Deep” Sandstone Injection and Confinement Zones “Shallow” Carbonate and Sandstone Injection and Confinement Zones “Intermediate“ Carbonate Reef Injection and Confinement Zones MI Storage Potential ~40Gt MI Emissions ~93Mt/yr }

12 12 Michigan Pilot Injection Test Project MRCSP is one of seven U.S. DOE/NETL RCSP’s. Eight-state region of IN, KY, MD, MI, NY, OH, PA, and WV. Phase I Launched, fall 2003; Phase II commenced October Michigan Basin site is one of three small scale CO 2 injection test sites.

13 Northern Michigan - MRCSP CO 2 Pilot Injection Test Well, Otsego Co., MI State Charlton #4-30 ~55,000 permitted Oil & Gas wells in MI “Shallow” Injection and Confinement Zone

14 Northern Michigan Pilot Injection Test Project; Otsego Co, MI

15 15 Results of Pilot CO 2 Injection Test Initial ~20 days of CO 2 injection: >10,000 mt Variable injection rates to pipeline Annualized injection rates: ~220,000 mt/yr Data extrapolation suggest maximum injection rates: ,000 mt/year Additional CO 2 of are being injected into the reservoir zone: 50,000 metric tons Analysis and interpretations of injection data by: Joel Sminchak, Battelle Memorial

16 16 “Deep” Sandstone Injection and Confinement Zones In Michigan

17 Mount Simon Sandstone in Michigan

18 18 “Deep” Injection and Confinement Zones; Ottawa Co. Michigan

19 Mount Simon Sandstone in Michigan

20 CO 2 Injection Simulation Modeling for a Large Stationary Point Source (~80Mw) 20 yr Active Injection; 280 year Recovery Model Parameters Injection Rate = 0.6 MMT/year for 20 yrs Recovery Period = 280 years Target Formation Interval: m Injection Interval: m Well Diameter: 8 5/8” casing Hydrostatic Gradient: 0.49 psi/ft Temperature: 50°C Brine: 300,000 ppm TDS Maximum Entrapped CO 2 Saturation = 0.2 Diana H Bacon Battelle Pacific Northwest

21 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

22 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

23 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

24 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

25 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

26 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

27 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

28 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

29 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

30 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

31 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

32 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

33 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

34 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

35 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

36 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

37 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

38 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

39 CO 2 Injection Well Active Injection Period Diana H Bacon Battelle Pacific Northwest

40 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

41 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

42 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

43 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

44 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

45 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

46 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

47 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

48 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

49 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

50 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

51 CO 2 Injection Well Recovery Period Diana H Bacon Battelle Pacific Northwest

52 CO 2 Injection Well Diana H Bacon Battelle Pacific Northwest Active Injection Period

53 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

54 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

55 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

56 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

57 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

58 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

59 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

60 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

61 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

62 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

63 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

64 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

65 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

66 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

67 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

68 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

69 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

70 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

71 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

72 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

73 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Active Injection Period

74 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

75 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

76 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

77 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

78 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

79 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

80 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

81 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

82 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

83 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

84 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

85 Diana H Bacon Battelle Pacific Northwest CO 2 Injection Well Recovery Period

86 86 CO 2 Injection Simulation Modeling Summary of Preliminary Results ½ space 2D Plume Dimensions after 300 years (20 years active injection, 280 years recovery) = ~3.8 km (2.3 mi) Active injection period lateral flow rate (~1.8 km/20yr) = ~90 m/yr Recovery period lateral flow rate (~2.0 km/280yr) = ~7.1 m/yr Diana H Bacon Battelle Pacific Northwest

87 87 CO 2 Injection Simulation Modeling Summary of Preliminary Results Little dissolved CO 2 –Due to high formation fluid salinity –Minimal perturbation of formation fluid reactivity Minimal formation pressure perturbation; rapid re-equilibration Diana H Bacon Battelle Pacific Northwest

88 Non-technical Challenges to Implementation of Carbon Capture and Geological Storage for Greenhouse Gas Emissions Reduction Public understanding and acceptance Clear legal and regulatory framework to stimulate investor confidence Sufficient cost for GHG emissions (that exceed cost of CC&GS) through regulation –Regional, National, and International Cap and Trade Programs/Carbon Tax

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