geologic sequestration: the big picture  estimation of storage capacity or how big is big enough

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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. - PowerPoint PPT Presentation

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  • Geologic Sequestration: the Big Picture Estimation of Storage Capacity or How Big is Big EnoughSusan Hovorka, Srivatsan Lakshminarasimhan, JP NicotGulf Coast Carbon CenterBureau of Economic GeologyJackson School of GeosciencesThe University of Texas at AustinPresented to TXU Carbon Management ProgramIAP 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 3,370 109 metric tons of CO2Saline AquifersCoal156 - 183109 metric tons of CO292 109 metric tons of CO2Oil and gas reservoirshttp://www.netl.doe.gov/publications/carbon_seq/atlas/index.html

  • Amount of CO2 to be sequestered7 x 109 T/year US emissions anthropogenic CO2If spread evenly over US as CO2:3 cm/year at @STP 0.04 mm/year at reservoir conditions

    Sources dot size proportional to emissions

    Sinks color proportional to thickness3.9 shown here

  • Options for Estimating CapacityVolumetric approach: Total pore volume x Efficiency factor (E)Free CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolvedVolume that can be stored beneath an area constrained by surface uses or by other unacceptable risks well fields, faultsPressure limits as a limit on capacityDisplaced water as a limit on capacityVolumetricRisk-based

  • Volumetric ApproachHow much will go in?Volumetric approach current state of artA focus on the two phase region: where is the CO2?

  • Risk or Consequences Approach to CapacityHow much will go in before unacceptable consequence occurs?

  • Fluid Displacement as a Limit on CapacityRate of injection limited by displacement of one fluid by anotherUnacceptable displacement of brine

  • Total Pore VolumeTotal pore volume = volume of fluids presently in the rock = porosity x thickness x area.Not all volume is usable:Residual waterMinimum permeability cut offSweep efficiency bypassing and buoyancy

  • Heterogeneity Dominant Control on VolumetricsStructural closure

  • Reservoir heterogeneity more important in injection than production

    3-D SeismicStratal SliceAmbrose (2000)1000 ft

  • Stacked ClosureHigher volumessummed though multiple zonesCornelius ReservoirMarkham No.Bay City No. fieldTyler andAmbrose (1986)

  • Efficiency in Terms of Use of Pore Volume by-passed volume

    A) Tom Daley LBNLCO2 Saturation Observed with Cross-well Seismic Tomography at FrioBy-passed volume

  • Hypothesis Capacity is Related To HeterogeneityCapacityHeterogeneity SealLow heterogeneity dominated by buoyancy SealHigh heterogeneity-poor injectivity SealJust right heterogeneityBaffling maximizes capacity

  • Options for Estimating CapacityVolumetric approach: Total pore volume x Efficiency factor (E)Free CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolvedVolume that can be stored beneath an area constrained by surface uses or by other unacceptable risks well fields, faultsPressure limits as a limit on capacityDisplaced water as a limit on capacity

  • Capacity: Dissolution of CO2 into Brine Volumetrically a big unknown

    1yr5 yr30 yr40 yr130 yr330 yr930 yr1330 yr2330 yrJonathan Ennis-King, CO2CRCJonathan Ennis-King, CSRIO

  • Rapid Dissolution of CO2 in Field Test a significant factor in reducing plume size Yousif Kahraka USGSWithin 2 days, CO2 has dissolved into brine and pH falls, dissolving Fe and Mn

    Chart1

    6.7527.8950808499

    6.7341.1757190784

    6.8334.3582749016

    6.6812.5559266973

    6.7522.0035725727

    6.52206.826036958

    6.47314.1040013477

    6.41482.4686163302

    6.46613.8950277473

    6.29925.2358109481

    6.26847.3193955709

    6.151115.3516429482

    6.04

    5.96

    6.41

    6.45

    6.44

    6.62

    6.27

    5.75

    5.78

    5.71

    5.74

    5.83

    5.62

    5.88

    5.88

    5.87

    6.03

    pH

    Fe

    Time

    pH

    Fe (mg/L)

    Frio CO2 injection (Oct. 4-7/04)

    Fe,pH

    Dayton-Frio 10/04 time plots 10/29/04 EK

    SAMPLEDATEtimepHTECFe 54

    10/4/04 12:2512:2521.2118000

    10/4/04 13:4513:4523

    10/4/04 14:5814:58

    10/4/04 16:1316:13

    10/4/04 18:3018:3021.3119100

    10/4/04 19:3119:31

    10/4/04 21:1721:17

    10/4/04 23:1823:186.75

    10/5/04 1:151:1521.51198004628

    10/5/04 3:143:146.7321.4120100

    10/5/04 5:105:106.83

    10/5/04 7:107:106.68

    10/5/04 11:1411:146.75

    10/5/04 13:2313:236.5221.51200003741

    10/5/04 15:1815:186.47

    10/5/04 17:1517:156.41

    10/5/04 19:2219:226.46

    10/5/04 21:1521:156.2921.6119500

    10/5/04 23:1023:106.26

    10/6/04 1:051:056.15

    10/6/04 3:023:026.0432

    10/6/04 4:554:555.9621.6119900

    10/6/04 6:506:506.4121.91197006034

    10/6/04 8:508:506.45

    10/6/04 10:5010:506.44

    10/6/04 12:5512:556.6221.81196003113

    10/6/04 14:5014:506.2721.61194004422

    10/6/04 15:4515:455.7521.31201001230207

    10/6/04 17:1517:155.7822.31195002100314

    10/6/04 18:1518:155.7122.0120600482

    10/6/04 20:0020:005.7423.2120100

    10/6/04 21:2021:205.8322.21189002180614

    10/6/04 22:2522:255.6220.7119000

    10/7/04 0:500:505.8818.0119300

    10/7/04 2:022:025.8819.71200002710925

    10/7/04 3:303:305.8719.51191002760847

    10/7/04 9:459:456.0321.111940029801115

    &R&D &T

    Fe,pH

    pH

    Fe

    Time

    pH

    Fe (mg/L)

    Frio CO2 injection (Oct.4-7/04)

    pH

    Fe

    Time

    pH

    Fe (mg/L)

    Frio CO2 injection (Oct. 4-7/04)

  • Options for Estimating CapacityVolumetric approach: Total pore volume x Efficiency factor (E)Free CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolvedVolume that can be stored beneath an area constrained by surface uses or by other unacceptable risks well fields, faultsPressure limits as a limit on capacityDisplaced water as a limit on capacity

  • Capacity in a Geographically limited area1-45-1010-30>30Wells perSq km

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

  • Do Not Need Structure to Limit Plume Size Role of Kv/KhSealKv
  • Options for Estimating CapacityVolumetric approach: Total pore volume x Efficiency factor (E)Free CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolvedVolume that can be stored beneath an area constrained by surface uses or by other unacceptable risks well fields, faultsPressure limits as a limit on capacityDisplaced water as a limit on capacity

  • Nearly Closed Volume Maximum Capacity May be Pressure Determined

  • Injection Pressure and DepthMaximum 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 CO2 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% porosity20% porosity30% porosity

  • Effect of Depth of formationEffect 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 = 0.01481 Vp

  • Options for Estimating CapacityVolumetric approach: Total pore volume x Efficiency factor (E)Free CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolvedVolume that can be stored beneath an area constrained by surface uses or by other unacceptable risks well fields, faultsPressure limits as a limit on capacityDisplaced water as a limit on capacity

  • Open Hydrologic System

  • Fluid Displacement From an Open Hydrologic SystemOutput 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 TexasFrom Dutton et al., 2003College StationWell FieldCO2 Injection

  • Fate of a Pressure Pulse in a Confined Aquifer

  • Year 2000heads Year 2050heads

  • ConclusionsVolumetric approach: DOE assessment shows more than adequate spaceFree CO2 volume in structural and stratigraphic trapsTrapped CO2 residual phaseVolume dissolved Significance and rate uncertainVolume 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 depthDisplaced water as a limit on capacity minor in large basins

    Fluid spills? Depending on saturation that may be OK how about bucket breaks?Is it necessary to confine CO2 injection to trap?Not sure If anyone has really said this is our mission statement but it sounds much stronger this wayNot sure If anyone has really said this is our mission statement but it sounds much stronger this wayThe 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 lin

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