Storage 1- Site Selection: Capacity and Injectivity
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1 Storage 1- Site Selection: Capacity and Injectivity JOHN KALDI Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) at University of Adelaide, Australia IEAGHG CCS SUMMER SCHOOL SVALBARD AUG, 2010 CO2CRC All rights reserved CO2CRC Participants Established & supported under the Australian Government s Cooperative Research Centres Program 1
2 Geological Storage of Carbon Dioxide Lots of uncertainty! Reducing the uncertainty with geological storage of CO 2 requires screening and site specific studies including reservoir characterisation, injection-migration modelling, monitoring, economics and risk analysis technologies commonly employed by the petroleum industry! 2
3 Site Selection for CO 2 Storage Projects: Critical Steps Site Deployment Full project economics work Risk assessment / management Monitoring and verification Community acceptance Regulatory regime in place Closure & liability issues resolved Bankable Project 3
4 Country/State/Region Screening Coarsest scale of assessment with the least site specific detail; Reconnaissance After Bachu & Shaw, 2005; CSLF, 2005 Identify sedimentary basins & screen and rank relatively quickly as to overall suitability for CO 2 storage before specific sites are identified and selected for further work. Determine size and thickness of the basin: quick clue to total pore volume Rule out areas beyond technical capability for drilling (eg deep water offshore) or politically or environmentally unviable areas (parks, refuges, urban areas, military zones, etc.) or areas of crystalline rocks; or depth where permeability is no longer sufficient to allow viable injection Identify oil, gas or other resources. Based on geological, geographical and industrial characteristics Basin Assessment Assessment criteria (Bachu, 2003) eg tectonic setting, basin size and depth, intensity of faulting, hydrodynamic and geothermal regimes, existing resources and industry maturity. Can be used in a semi quantitative manner to rank basins within a particular state or region. Identify reservoir and seal pairs. Establish depths for CO 2 to be supercritical Identify potential migration pathways Identify potential sites After Bachu & Shaw, 2005; CSLF,
5 Is the most time-consuming and costly part of the CO 2 storage site selection process! Site Characterisation Typically involves greater detail than basin assessment; includes evaluation (or re-evaluation) of regional/structural geology, generation of new and/or updating of existing stratigraphic and seismic i interpretations, i static and dynamic models (flow simulation ), geomechanics, and ultimately injection. Data sources include 2D and 3D seismic surveys, well logs, core data, drill cuttings, biostratigraphy, analogs, field production and fluid data. After Bachu & Shaw, 2005; CSLF, 2005 Screen & rank potential sites using, site specific geological criteria for -Injectivity -Capacity -Containment Criteria for Site Characterisation: Injectivity (can we put the CO 2 into the rock?) Containment (can we keep the CO 2 in the rock?) Capacity (what volume of CO 2 can the rock hold?) 5
6 Storage Capacity Estimation Techno-Economic Resource-Reserve Pyramid for CO 2 Storage Capacity CO2CRC, 2008 Modified from Bachu et al., CSLF, 2005 Storage Capacity Estimation Total Pore Volume Total physical limit of what the storage system can accept. Assumes entire volume is accessible to store CO 2 in the pore space or dissolved in formation fluids or adsorbed at 100% onto total coal volume. This represents the maximum upper limit to a capacity estimate. However, this is an unrealistic number as there will always be physical, technical, regulatory and economic limitations. 6
7 Storage Capacity Estimation Prospective Capacity Subset of Total Pore Volume and obtained by applying technical (geological & engineering) limits. This estimate usually changes with acquisition of new data or knowledge Storage Capacity Estimation Contingent Capacity Subset of prospective capacity obtained by considering technical, legal and regulatory, infrastructure and general economic barriers. Value prone to changes as technology, policy, regulations and/or economics change. Corresponds to Reserves as used in energy and mining industries 7
8 Storage Capacity Estimation Operational Capacity Subset of contingent capacity obtained by detailed d matching of large, stationary ti sources with geological storage sites that are adequate in terms of capacity, injectivity and supply rate. Corresponds to Proved, marketable reserves used by mining industry Volumetric Equation for Capacity Calculation G CO2 = A h g φ ρ E G CO2 = Volumetric storage capacity A = Area (Basin, Region, Site) being assessed H g = Gross thickness of target saline formation defined by A φ ρ =Avg. porosity over thickness h g in area A = Density of CO 2 at Pressure & Temperature of target tsaline formation E = Storage efficiency factor (fraction of total pore volume filled by CO 2 ) NETL DOE,
9 Storage Capacity Estimation Techno-Economic Resource-Reserve Pyramid for CO 2 Storage Capacity x E 1 4% CO2CRC, 2008 Modified from Bachu et al., 2005 (van der Meer and others) Supercritical CO 2 CO 2 injected as supercritical fluid Gas-type behaviour but liquid-like densities CO 2 supercritical at ~31.1 o C & 7.38 MPa Average depth ~800m 9
10 CO 2 storage effectiveness increases with depth Geological Storage of CO 2 What do we need? RESERVOIR ROCK porous, e.g. sandstone Claystone seal rock SEAL ROCK nonporous, e.g. claystone Sandstone reservoir rock 10
11 Geological Storage of CO 2 Porosity is the storage space in the rock for fluids and is shown by the blue spaces in this photograph of a thin slice through a reservoir sandstone. Claystone seal rock Permeability is a measure of the ability of the rock to allow fluid flow. Permeability is strongly affected by the geometry of the porosity in particular the size of the spaces connecting the pores in the rock (red circles). Permeability is main control on injectivity Sandstone reservoir rock Scanning Electron Microscope (SEM) view of pore space in sandstone 11
12 PORES & PORE THROATS Pore Pore Grain Throat Throat Injection of CO 2 into reservoir SEAL RESERVOIR CAPILLARY PRESSURE BUOYANCY PRESSURE SEAL UPWARD MIGRATION OF CO 2 DRIVEN BY BUOYANCY (DENSITY DIFFERENCE BETWEEN WATER AND CO 2 ) (Δρ) BUOYANCY PRESSURE IS OPPOSED BY CAPILLARY PRESSURE (DISPLACEMENT PRESSURE OF PORE THROATS) (Pd) 12
13 Capillarity Effects: Buoyancy vs Displacement Pressure Pb = Δρgh Pb < Pd Pb > Pd CO 2 Sw = 100% CO 2 S CO2 = 0 Sw < 100% S CO2 > 0 MOVEMENT OF CO 2 THROUGH PORE SYSTEM... DRAINAGE Pb = Δρgh PORE A thin film of water remains around each grain: Irreducible water saturation Swirr THROAT In order to migrate CO 2 needs sufficient Pb to exceed Pd at each pore throat CO2 Injected CO 2 enters reservoir pore system 13
14 CO 2 Storage Trapping Mechanisms Structural / Stratigraphic Trapping (SST) Most familiar; best understood; lowest risk From IPCC SRCCS, 2005 Structural traps for CO 2 Issues: Storage volume (capacity) Injectivity (rate, press, cost) Seal potential (contaiment) 14
15 Storage capacity controlled by rock type (not just porosity) 250 μm Rock A: φ = 28.4% k = 1394 md Rock B:φ = 28.4% k = 0.22 md Irreducible water saturation: a critical control on storage capacity < frac pressure Swirr = 7% Swirr = 82% Injection pressure Rock A θ = 28.4% k = 1394 md Rock B θ = 28.4% k = 0.22 md Wetting phase (water) saturation
16 Storage capacity issues: depleted reservoirs/structural traps S wirr S gr 1000 s of metres S wirr S or Seal Reservoir S. Holl Seal Reservoir CO 2 Storage Trapping Mechanisms Migration Associated Trapping (MAT) From IPCC SRCCS, 2005 Least familiar modelled, but poorly understood highest uncertainty focus of many storage demo projects 16
17 MAT: Storage in Deep Saline Formations Sample only Migration Associated Trapping (MAT) CO 2 Trapped in solution CO 2 Trapped as a mineral CO 2 Trapped in rock pores as Residual Saturation (Sgr CO2 ) 17
18 CO 2 storage effectiveness increases with time (Modelling the dissolution of injected CO 2 ) 1yr Homogeneous Reservoir Flat-lying Seal Cross-sectional view 5 yr 30 yr From: J. Ennis-King CO 2 storage effectiveness increases with time (Modelling the dissolution of injected CO 2 ) 40 yr 130 yr 330 yr From: J. Ennis-King 18
19 CO 2 storage effectiveness increases with time (Modelling the dissolution of injected CO 2 ) 930 yr 1330 yr 2330 yr From: J. Ennis-King Mineral trapping: also increases with time Calcite cement (red) 1 m 1 mm 1 cm CaCO 3 (Calcite) precipitation occurs at all scales at different rates 200 μm 19
20 Migration Associated Trapping (MAT) CO 2 Trapped in solution CO 2 Trapped as a mineral CO 2 Trapped in rock pores as Residual Saturation (Sgr CO2 ) RESIDUAL CO 2 SATURATION BY PLUME MIGRATION... IMBIBITION Residual CO2 CO2 Grain Snap-off H 2 O 20
21 Residual CO 2 Saturation Swirr (max CO 2 saturation) CO 2 INJECTION PRESSURE (Below P Frac) Drainage (Injection in Real Time) Imbibition (Plume Migration Time) 0 S R S 100 Residual Mercury Saturation (% Pore Volume) Water Saturation (% Pore Volume) Residual Saturation (Sgr CO2 ) Controlled by Pore Geometry: pore/throat size ratio Lower pore/throat size ratio: lower Sgr hc (better oil/gas recovery) lower Sgr co2 (worse CO 2 storage) Pore Throat Higher pore/throat size ratio: higher Sgr hc (worse oil/gas recovery) higher Sgr co2 (better CO 2 storage) Pore Throat 21
22 Pore Geometry: Coordination (throats/pore) Higher coordination: lower Sgr hc (better oil/gas recovery) lower Sgr co2 (worse CO 2 storage) Throat Pore Lower coordination: higher Sgr hc (worse oil/gas recovery) higher Sgr co2 (better CO 2 storage) Pore Throat φ = 18.2% K= 85 md 250 μm φ = 28.4% K= 1394 md 5 mm 22
23 < frac pressure Swirr Rock A (interparticle porosity) Low P/T Ratio; High Coordination Injection pressure CO 2 Injection (drainage) CO 2 plume migration (imbibition) Sgr co Wetting phase (water) saturation < frac pressure Swirr Rock C (vuggy porosity) High P/T Ratio; Low Coordination CO 2 Injection (drainage) Injection pressure CO 2 plume migration (imbibition) Sgr co Wetting Phase (Water) Saturation
24 CO 2 Migration Injection (Drainage (Imbibition cycle) cycle) High Residual CO 2 Saturation Vuggy Limestone Reservoir 5 mm Injectivity I v/t = A * P i * k I v/t A P i k = Injection rate = Area (of wellbore in contact with formation) = injection pressure (below frac) = permeability (I v/t is proportional to number of wells) 24
25 Frac Pressure (P frac ) re above initial press sure (Bar) + Pressu Injection rate (l/s) Injectivity / Pressure Considerations: Injection of fluids (eg CO 2 ) causes reservoir pressure build up In depleted fields, pressure build-up may be neutral or beneficial In both depleted fields and saline aquifers, must maintain pressure below fracture pressure In low permeability reservoirs this may limit economic storage capacity due to decreased injection rate, requiring more wells Injection in saline formations may displace saline fluids & increase risk of possible mixing i with freshwater system Drilling pressure relief (water production) wells possible solution 25
26 Depleted Field (pressure v. Time)) P frac Initial P res Pressure o/g production CO 2 injection Water production (pressure relief) Time Saline Formation (pressure v. time) P frac Initial P res CO 2 injection Pressure CO 2 injection Water production (pressure relief) Time 26
27 Critical Consideration: Economics t Storage capacity MMt Carbon price Allinson & Paterson, 2009 Thank you 27
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