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  • Introduction Injectivity and Economics Assessing the ...€¦ · 3. Construct 3D Reservoir Model Using Geostatistics 4. Simulate CO 2 Injection 5. Evaluate CO 2 Injection and Sequestration
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Annual GCEP Symposium 2007 Contact: Amie Lucier at [email protected] Amie Lucier and Mark Zoback, Department of Geophysics, Stanford University Assessing the economic feasibility of regional deep saline aquifer CO 2 injection and sequestration: A geomechanics-based workflow applied to the Rose Run Sandstone in Eastern Ohio - Typical top-down regional assessments of CO 2 sequestration feasibility determine the maximum volumetric capacity of deep saline aquifers, but do not reflect the economic feasibility of sequestration of a region - The CO 2 sequestration capacity of an aquifer is a function of its porous volume as well as its CO 2 injectivity. - Economic feasibility is controlled, in part, by the number and type of injection wells necessary to achieve regional CO 2 sequestration goals - Economic feasibility is also affected by the cost of transporting CO 2 . Transportation costs can be minimized by identifying injection sites near to large point sources. - Injection sites closest to large point sources may not be the most “ideal” injection reservoirs - In this study, we present a methodology to evaluate the economic feasibility of CO 2 sequestration in regions with many large point sources, but less than ideal injection reservoirs - The geomechanics-based assessment workflow that we present in this poster follows a bottom-up approach for evaluating regional deep saline aquifer CO 2 sequestration feasibility - A site is considered feasible CO 2 can be injected at a reasonable cost per ton of CO 2 , as defined by injection rate and well costs - A region is considered feasible if it has enough sites to store a specified amount of CO 2 at reasonable cost per ton of CO 2 , as defined by the number and costs of wells needed to met the CO 2 project goals Introduction Injectivity and Economics Rose Run Sandstone Case Study 1. Define CO 2 Sequestration Project and Goals - Study location area - Amount of CO 2 to be sequestered - Economic controls/limitations 2. Regional Characterization 3. Construct 3D Reservoir Model Using Geostatistics - Build 3D grid with geometry consistent with regional structure - Use geostatistics to populated models with all possible combinations of hydrogeologic property distributions 4. Simulate CO 2 Injection - Injection rates are limited by fracture pressure and/or critical fault slip pressure of caprock - Project goals define the time period over which simulations are run 5. Evaluate CO 2 injection and Sequestration Feasibility - Categorize each model by likelihood of occurring in the region - Calculate cost/ton of CO 2 for each injection model - Determine feasibility of achieving sequestration goals within the defined spatial and economic controls a. Characterize the Geology - Characterize structure, rock and hydrogeologic properties of aquifer and caprock - Define reasonable regional distributions of hydro- geologic properties b. Characterize the Geomechanics - Build regional geomechanical model of in situ stress state - Assess feasibility of incorporating injectivity/ permeability enhancement techniques 6. Evaluate Injectivity Enhancement Techniques for Improved CO 2 Sequestration Feasibility a. Vertical Well with Hydraulic Fracture b. Vertical Well with Induced Micro- Seismicity c. Horizontal Well with Hydraulic Fractures d. Horizontal Well with Induced Micro- Seismicity a. Proceed with Sequestration Assessment - Update regional results by screening more local sites - Refine assessment with new data b. Abandon regional plans for sequestration 7. Regional Sequestration Assessment Geomechanics-Based Workflow Discussion Likelihood of Fault Slip as a function of fracture pole orientation (lower hemisphere projection) 10 15 20 25 Critical P p gradient, MPa/km S Hmax N P p high low Shmin caprock 16 21 26 0 2 4 6 Normal stress gradient, MPa/km Shear stress gradient, MPa/km µ=0.6 S Hmax S v Critically stressed fractures in the Rose Run Not critically stressed fractures in the Rose Run Critically stressed fractures in the Rose Run at P p =S hmin caprock P p S hmin caprock In situ P p Critically stressed fractures in the Rose Run at P p =S hmin Rose Run P p =S hmin Rose Run P p =S hmin caprock S hmin Rose Run P p increasing with injection CO 2 Saturation 0.1 0.3 0.2 0.4 0.5 0.6 Vertical Injection Wells Horizontal Injection Wells 32 MPa BHP 40 MPa BHP Hydraulic Fracture 0 2 4 6 8 10 12 14 16 18 0 10 20 30 Cumulative Injection, Mt CO 2 Time, years 32 MPa BHP 40 MPa BHP Hydraulic Fracture 32 MPa BHP 40 MPa BHP Hydraulic Fracture A. B. Summary of CO 2 Injection Simulation Results after 30 Years for Model T60_K20_P8 N 10 X Vertical Exaggeration BHP 32 MPa BHP 40 MPa Mean Thickness 30 m (T30) [1] Mean Thickness 60 m (T60) [3] Mean Perm. 4 md (K4) [1] Mean Perm. 20 md (K20) [2] Mean Perm. 40 md (K40) [3] Mean Porosity 4 % (P4) [2] Mean Porosity 8 % (P8) [1] Mean Porosity 12 % (P12) [3] Subtotal: 36 Injection Simulations Structural Variability Property Variability Vertical Injection Well BHP 32 MPa BHP 40 MPa Mean Thickness 30 m (T30) [1] Mean Thickness 60 m (T60) [3] Mean Perm. 4 md (K4) [1] Mean Perm. 20 md (K20) [2] Mean Perm. 40 md (K40) [3] Mean Porosity 4 % (P4) [2] Mean Porosity 8 % (P8) [1] Mean Porosity 12 % (P12) [3] Subtotal: 36 Injection Simulations Horizontal Injection Well Total: 108 Injection Simulations BHP 42 MPa Mean Thickness 30 m (T30) [1] Mean Thickness 60 m (T60) [3] Mean Perm. 4 md (K4) [1] Mean Perm. 20 md (K20) [2] Mean Perm. 40 md (K40) [3] Mean Porosity 4 % (P4) [2] Mean Porosity 8 % (P8) [1] Mean Porosity 12 % (P12) [3] Subtotal: 18 Injection Simulations Structural Variability Property Variability Vertical Injection Well with Single Hydraulic Fracture BHP 42 MPa Mean Thickness 30 m (T30) [1] Mean Thickness 60 m (T60) [3] Mean Perm. 4 md (K4) [1] Mean Perm. 20 md (K20) [2] Mean Perm. 40 md (K40) [3] Mean Porosity 4 % (P4) [2] Mean Porosity 8 % (P8) [1] Mean Porosity 12 % (P12) [3] Subtotal: 18 Injection Simulations Horizontal Injection Well with Four Hydraulic Fractures 0 0.3 0.6 0.9 1.2 1.5 T30_K4_P4 T30_K4_P8 T30_K4_P12 T30_K20_P4 T30_K20_P8 T30_K20_P12 T30_K40_P4 T30_K40_P8 T30_K40_P12 T60_K4_P4 T60_K4_P8 T60_K4_P12 T60_K20_P4 T60_K20_P8 T60_K20_P12 T60_K40_P4 T60_K40_P8 T60_K40_P12 Mt CO 2 /yr 0 0.3 0.6 0.9 1.2 1.5 T30_K4_P4 T30_K4_P8 T30_K4_P12 T30_K20_P4 T30_K20_P8 T30_K20_P12 T30_K40_P4 T30_K40_P8 T30_K40_P12 T60_K4_P4 T60_K4_P8 T60_K4_P12 T60_K20_P4 T60_K20_P8 T60_K20_P12 T60_K40_P4 T60_K40_P8 T60_K40_P12 Mt CO 2 /yr CO 2 Injection Rate Averaged over 30 Years of Injection Vertical Well (BHP=32 MPa) Horizontal Well (BHP=32 MPa) Vertical Well Hydraulic Fracture (BHP=42) Horizontal Well Hydraulic Fracture (BHP=42) Vertical Well (BHP=40 MPa) Horizontal Well (BHP=40 MPa) Vertical Well Hydraulic Fracture (BHP=42) Horizontal Well Hydraulic Fracture (BHP=42) 0.00 2.50 5.00 7.50 10.00 12.50 15.00 17.50 20.00 22.50 25.00 Vertical Well 32 MPa BHP Vertical Well 40 MPa BHP 1.31 More Likely Less Likely Associated Well Cost US$/t CO 2 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 Vertical Well 32 MPa BHP Vertical Well 40 MPa BHP Regional Area Required 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Vertical Well 32 MPa BHP Vertical Well 40 MPa BHP Number of Wells Required 522 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 A. B. C. 0 2 4 6 8 10 12 14 16 18 20 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 More Likely Less Likely Associated Well Costs US$/t CO 2 Regional Area Required Number of Wells Required 1.31 Vertical Well Hydraulic Fracture Estimated VW Micro-seismicity Horizontal Well (32 MPa BHP) Horizontal Well (40 MPa BHP) Horizontal Well Hydraulic Fracture Estimated HW Micro-seismicity Vertical Well Hydraulic Fracture Horizontal Well (32 MPa BHP) Horizontal Well (40 MPa BHP) Horizontal Well Hydraulic Fracture Vertical Well Hydraulic Fracture Estimated VW Micro-seismicity Horizontal Well (32 MPa BHP) Horizontal Well (40 MPa BHP) Horizontal Well Hydraulic Fracture Estimated HW Micro-seismicity A. B. C. 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 3_T30_K4_P8 4_T30_K4_P4 4_T30_K20_P8 5_T30_K4_P12 5_T60_K4_P8 5_T30_K20_P4 5_T30_K40_P8 6_T60_K4_P4 6_T30_K20_P12 6_T60_K20_P8 6_T30_K40_P4 7_T60_K4_P12 7_T60_K20_P4 7_T30_K40_P12 7_T60_K40_P8 8_T60_K20_P12 8_T60_K40_P4 9_T60_K40_P12 Average kH (permeability thickness), m 3 X10 -9 Not Feasible: Costs > Maximum Economic Threshold of 1.31 US$/t CO 2 Likely Feasible: Costs Within the Range of Economic Thresholds of 0.875-1.31 US$/t CO 2 Feasible: Costs < Minimum Economic Threshold of 0.875 US$/t CO 2 Injection Scenario 0.1 1 10 Vertical Well: 32 MPa BHP Vertical Well: 40 MPa BHP Horizontal Well: 32 MPa BHP Horizontal Well: 40 MPa BHP Vertical Well: Hydraulic Fracture Horizontal Well: Hydraulic Fractures Vertical Well: Induced Micro-seismicity Horizontal Well: Induced Micro-seismicity Economic Transition for Threshold of 1.31 US$/t CO 2 Injection Scenario 0.1 1 10 Vertical Well: 32 MPa BHP Vertical Well: 40 MPa BHP Horizontal Well: 32 MPa BHP Horizontal Well: 40 MPa BHP Vertical Well: Hydraulic Fracture Horizontal Well: Hydraulic Fractures Vertical Well: Induced Micro-seismicity Horizontal Well: Induced Micro-seismicity Economic Transition for Threshold of 1.31 US$/t CO 2 Economic Transition for Threshold of 2.62 US$/t CO 2 Economic Transition for Threshold of 3.93 US$/t CO 2 Economically Feasible Not Economically Feasible A. B. Average kH (permeability thickness), m 3 X10 -9 1900 2050 2200 2350 2500 2650 2800 0 20 40 60 80 100 Depth [m] Pressure [MPa] P p S v S hmin S Hmax minifrac Strike-Slip Frictional Faulting Equilibrium Trenton Limestone Beekmantown Dolomite Rose Run Ss. Copper Ridge Dolomite Nolichucky Shale Upper Maryville Dolomite Lower Maryville Sandstone 1. Define the CO 2 Sequestration Project and Goals a. Characterize the Geology b. Characterize the Geomechanics 3. Construct 3D Reservoir Model Using Geostatistics 4. Simulate CO 2 Injection 5. Evaluate CO 2 Injection and Sequestration Feasibility 7. Regional Sequestration Assessment 2. Regional Characterization 6. Evaluate Injectivity Enhancement Techniques for Improved CO 2 Sequestration Feasibility - This assessment methodology is a tool for estimating regional effective CO 2 sequestration capacity - It considers: 1. Available aquifer storage volumes 2. Realistic well injection rates 3. The costs associated with drilling and maintaining injection wells - It utilizes: 1. Geological Characterization 2. Geomechanical Characterization 3. Aquifer Modeling 4. CO 2 injection simulation - Regions are evaluated at the scale of individual injection intervals that represent the heterogeneity and uncertainty of regional aquifer properties - In regions with low-to-moderate permeability and aquifer thickness, the injectivity of an aquifer may severely limit its effective storage potential - Aquifer stimulation techniques can increase injectivity and decrease costs - Carrying out a geomechanical analysis at a proposed injection site is necessary for: 1. Controlling injection pressures 2. Formulating stable deviated well trajectories 3. Developing hydraulic fracture treatments 4. Characterizing existing hydraulically conductive fractures 5. Planning induced micro-seismicity treatments - For CO 2 sequestration to be practical in a large portion of the Midwestern United States, stimulation techniques will need to be employed - The permeability, k, and the thickness, H, are the primary properties controlling the injection rate - Models are more likely to be economically feasible if they have large kH values and are stimulated with hydraulic fractures or induced micro-seismicity - At a higher cost per ton of CO 2 , some models with smaller kH values and less stimulation become economically feasible - With simple vertical or even horizontal injection wells, the region is unlikely to have enough injection capacity to make CO 2 sequestration feasible - The Rose Run region meets the spatial requirements for sequestering 113 Mt CO 2 /yr for 30 years. - The Rose Run region is likely a feasible location for CO 2 sequestration - Several areas of investigation will lead to a more complete assessment 1. Characterize the stress state at more locations 2. Find trends in aquifer thickness and permeability to optimize kH values 3. Injection induced micro-seismicity experiments to determine the potential for increasing injectivity in the region The goal of this project is to sequester 90% of the emissions from the 23 power plants near the case study area for 30 years at the current emissions rate of 126 Mt CO 2 /yr (i.e. 113 Mt CO2/yr or 3.39 Gt CO 2 over 30 years) The economic constraints limit the costs associated with drilling and maintaining the injection wells in the region to ideally less than 0.875 US$/t CO 2 but up to 1.31 US$/t CO 2 (based on regional cost of energy and emissions rates) The associated well costs are estimated by the type of well, stimulation techniques, and maintenance costs for the lifetime of the well Study Area: - Rose Run is 2350±100 m deep (36 km X 360 km) - Corresponds to the depth of the Rose Run at the Mountaineer power plant - Near 23 large point sources, which emit approximately 126 Mt CO 2 /yr Well Type Initial Cost (M US$) Lifespan (years) Annual Maintenance Cost (M US$) Total Well Cost (M US$) Maximum # of Wells Vertical well 4.0 30 0.15 8.5 522 Vertical well with hydraulic fracture 4.5 30 0.15 9.0 493 Vertical well with induced micro-seismicity 5.5 30 0.15 10.0 444 Horizontal well 6.0 30 0.15 10.5 423 Horizontal well with 4 hydraulic fractures 7.5 30 0.15 12.0 370 Horizontal well with induced micro-seismicity 8.5 30 0.15 13.0 342 The mean thickness of the Rose Run is about 30 m, but in some areas it can be more than 60 m thick We defined three lognormal porosity distributions to evaluate with mean porosity values of 4%, 8%, and 12%. We modeled three multigaussian log permeability distributions: (1) ranging from 1.6-25 md and a mean of about 4 md, (2) ranging from 8-125 md with a mean of about 20 md, and (3) ranging from 16-250 with a mean of about 40 md. 5 10 15 20 25 30 Porosity [%] 1 10 100 1000 Permeability [mD] N We modeled two aquifer thicknesses 1. Averaging 30 m (varying from 15 to 50 m) 2. Averaging 60 m (varying from 45 to 80 m) We modeled each aquifer thickness three times: 1. Without a hydraulic fracture 2. With a single hydraulic fracture 3. With four, smaller, staggered hydraulic fractures that represent hydraulic fracturing along a horizontal well. We populated the models with porosity and permeability values using sequential Gaussian simulation with 9 possible property combinations 1. Mean porosity = 4%, 8%, or 12% 2. Mean permeability = 4 md, 20 md, or 40 md A. CO 2 saturation after 30 year of injection for the six injection scenarios that are simulated B. Cumulative CO 2 injection over 30 years for the six scenarios Stress magnitudes at the Mountaineer Site. The minifrac tests (red) indicate that the S hmin magnitude has two trends. It is significantly less in the Rose Run than that above and below. This means hydraulic fracturing is feasible. S v =62 S Hmax =54 S hmin =34 P p =P m =26 TENDENCY FOR BREAKOUTS AT 2365 m DEPTH Stress Magnitudes [MPa] Rose Run: Normal Faulting Stress Regime Rock Strength [MPa] to Prevent Breakouts with >30 o Width S Hmax 65 70 75 80 85 90 N Horizontal Well in S hmin Direction Vertical Well Well trajectories with hot colors require higher rock strengths to prevent breakouts and are therefore less stable. The Rose Run rock strength is more than 200 MPa at the Mountaineer site, so all well trajectories are stable the Rose Run stress state. Fractures in the Rose Run sandstone. The lower hemisphere stereonet plot indicates likelihood of fault slip as a function of pole to the fracture plane. Fractures are also plotted on a Mohr diagram. Critically stressed faults often act as conduits for flow and enhance permeability. The presence of critically stressed faults make induced microseismicity a feasible stimulation technique. Outline of fluid flow simulations, organized by injection scenario. BHP is bottom hole pressure used to constrain injection rates, and is constrained by S hmin . The abbreviations in ( ) refer to the naming convention. The number in [ ] categorizes the likelihood of a property to be found in the region, [1] is most and [3] is least likely. CO 2 injection rate averaged over 30 years of injection. Simulations are sorted in order by thickness (T30, T60), permeability (K4, K20, K40), and porosity (P4, P8, P12). Injection interval models are ranked by their likelihood of occurring in the region based on their hydrogeological property values 1. We added up the values (1-3) for the 3 properties to get a ranking value from 3 to 9 2. Models with lower values are more representative of the regional aquifers 3. The ranking values are appended to the beginning of the model names. We examined whether the sequestration goals could be met honoring spatial constraints 1. We calculated the surface area of the top of the CO 2 plume after 30 years of injection 2. Determined how many injection wells would be necessary to inject 113 Mt CO2/yr 3. We calculated the percentage of the regional area required to reach the goal 4. All of the potential injection scenarios met the spatial feasibility constraint. We determine if economic constraints could also be honored (i.e., the sequestration goal is met with fewer than 522 vertical wells or an associated well cost of less than $1.31/t CO2) 1. For a BHP of 32 MPa, 3 models with ranking values > 6 honor the constraint 2. For a BHP of 40 MPa, 10 models honor the constraint, 4 of these have a ranking value of 5 or 6 (moderately likely) 3. It is unlikely that the study area contains enough sites similar to these models to meet its sequestration goals using only vertical injection wells. We showed that injection scenarios such as using horizontal wells, hydraulically fracturing vertical or horizontal wells, and induced micro-seismicity within the aquifer were all feasible ways to increase injection rates However, these potential increases in injection rates come with higher associated well costs. All of the enhanced injectivity scenarios honor the regional spatial constraints We determine if the economic constraints could also be honored 1. In induced micro-seismicity cases we assumed that the injection rate was five times that of the vertical or horizontal wells simulated with a 40 MPa BHP 2. The number of wells required to sequester 113 Mt CO 2 /yr was estimated for the 6 potential injectivity enhancement techniques 3. When the number of wells was translated into associated well costs per ton of CO 2 , 15 of the 18 models had at least one injection scenario that was within the feasibility threshold of 1.31 US$/t of CO 2 . 4. Horizontal wells alone do not reduce the costs enough to be economical 5. Injection wells with hydraulic fracturing and/or induced micro-seismicity increases the likelihood that Rose Run sequestration goals can be reached. P p is pore pressure, S hmin is the minimum horizontal compressive stress, S Hmax is the maximum horizontal compressive stress, S v is the vertical stress Ohio Indiana West Virginia Kentucky 87 ° W 85 ° W 83 ° W 81 ° W 79 ° W 37 ° N 38 ° N 39 ° N 40 ° N 41 ° N 42 ° N Earthquake Magnitude 2 4 3 5 CO 2 Emissions [Mt/yr] 0.5 5 1 10 Ohio River

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Page 1: Introduction Injectivity and Economics Assessing the ...€¦ · 3. Construct 3D Reservoir Model Using Geostatistics 4. Simulate CO 2 Injection 5. Evaluate CO 2 Injection and Sequestration

Annual GCEP Symposium 2007 Contact: Amie Lucier at [email protected]

Amie Lucier and Mark Zoback, Department of Geophysics, Stanford University

Assessing the economic feasibility of regional deep saline aquifer CO2 injection and sequestration:

A geomechanics-based workflow applied to the Rose Run Sandstone in Eastern Ohio - Typical top-down regional assessments of CO2 sequestration feasibility

determine the maximum volumetric capacity of deep saline aquifers, but do not reflect the economic feasibility of sequestration of a region

- The CO2 sequestration capacity of an aquifer is a function of its porous

volume as well as its CO2 injectivity.

- Economic feasibility is controlled, in part, by the number and type of injection wells necessary to achieve regional CO

2 sequestration goals

- Economic feasibility is also affected by the cost of transporting CO2.

Transportation costs can be minimized by identifying injection sites near to large point sources.

- Injection sites closest to large point sources may not be the most “ideal” injection reservoirs

- In this study, we present a methodology to evaluate the economic feasibility of CO

2 sequestration in regions with many large point sources,

but less than ideal injection reservoirs

- The geomechanics-based assessment workflow that we present in this poster follows a bottom-up approach for evaluating regional deep saline aquifer CO

2 sequestration feasibility

- A site is considered feasible CO2 can be injected at a reasonable cost per

ton of CO2, as defined by injection rate and well costs

- A region is considered feasible if it has enough sites to store a specified amount of CO

2 at reasonable cost per ton of CO

2, as defined by the

number and costs of wells needed to met the CO2 project goals

Introduction Injectivity and Economics

Rose Run Sandstone Case Study

1. Define CO2 Sequestration Project and Goals - Study location area - Amount of CO2 to be sequestered - Economic controls/limitations

2. Regional Characterization

3. Construct 3D Reservoir Model Using Geostatistics - Build 3D grid with geometry consistent with regional structure - Use geostatistics to populated models with all possible combinations of hydrogeologic property distributions

4. Simulate CO2 Injection - Injection rates are limited by fracture pressure and/or critical fault slip pressure of caprock - Project goals define the time period over which simulations are run

5. Evaluate CO2 injection and Sequestration Feasibility - Categorize each model by likelihood of occurring in the region - Calculate cost/ton of CO2 for each injection model - Determine feasibility of achieving sequestration goals within the defined spatial and economic controls

a. Characterize the Geology - Characterize structure, rock and hydrogeologic properties of aquifer and caprock - Define reasonable regional distributions of hydro- geologic properties

b. Characterize the Geomechanics - Build regional geomechanical model of in situ stress state - Assess feasibility of incorporating injectivity/ permeability enhancement techniques

6. Evaluate Injectivity Enhancement Techniques for Improved CO2 Sequestration Feasibility

a. Vertical Well with Hydraulic Fracture

b. Vertical Well with Induced Micro- Seismicity

c. Horizontal Well with Hydraulic Fractures

d. Horizontal Well with Induced Micro- Seismicity

a. Proceed with Sequestration Assessment - Update regional results by screening more local sites - Refine assessment with new data

b. Abandon regional plans for sequestration

7. Regional Sequestration Assessment

Geomechanics-Based Workflow Discussion

Likelihood of Fault Slipas a function of fracture pole orientation

(lower hemisphere projection)

10 15 20 25 Critical Pp gradient, MPa/km

SHmax

N

Pp

high lowShmin caprock

16 21 260

2

4

6

Normal stress gradient, MPa/km

She

ar s

tress

gra

dien

t,M

Pa/

km

µ=0.6

SHmax Sv

Critically stressed fractures in the Rose Run

Not critically stressed fractures in the Rose Run

Critically stressed fractures in the Rose Run at Pp=Shmincaprock

Pp Shmincaprock

In situ P p

Critically stressed fractures in the Rose Run at Pp=ShminRose Run

P p=S hmin

Rose Run

P p=S hmin

caprock

ShminRose Run

Pp increasing with injection

CO2 Saturation0.1 0.30.2 0.4 0.5 0.6

Vertical Injection Wells Horizontal Injection Wells

32 MPa BHP

40 MPa BHP

Hydraulic Fracture

0

2

4

6

8

10

12

14

16

18

0 10 20 30

Cum

ulat

ive

Inje

ctio

n, M

t CO

2

Time, years

32 MPa BHP

40 M

Pa B

HP

Hyd

raul

ic F

ract

ure

32 MPa BHP

40 MPa BHP

Hydraulic Fracture

A. B.

Summary of CO2 Injection Simulation Results after 30 Years for Model T60_K20_P8

N10 X Vertical Exaggeration

BHP32 MPa

BHP40 MPa

Mean Thickness30 m (T30) [1]

Mean Thickness60 m (T60) [3]

Mean Perm.4 md (K4) [1]

Mean Perm.20 md (K20) [2]

Mean Perm.40 md (K40) [3]

Mean Porosity4 % (P4) [2]

Mean Porosity8 % (P8) [1]

Mean Porosity12 % (P12) [3]

Subtotal: 36 Injection Simulations

Stru

ctu

ral

Vari

abili

tyPr

op

erty

Var

iab

ility

Vertical Injection Well

BHP32 MPa

BHP40 MPa

Mean Thickness30 m (T30) [1]

Mean Thickness60 m (T60) [3]

Mean Perm.4 md (K4) [1]

Mean Perm.20 md (K20) [2]

Mean Perm.40 md (K40) [3]

Mean Porosity4 % (P4) [2]

Mean Porosity8 % (P8) [1]

Mean Porosity12 % (P12) [3]

Subtotal: 36 Injection Simulations

Horizontal Injection Well

Total: 108 Injection Simulations

BHP42 MPa

Mean Thickness30 m (T30) [1]

Mean Thickness60 m (T60) [3]

Mean Perm.4 md (K4) [1]

Mean Perm.20 md (K20) [2]

Mean Perm.40 md (K40) [3]

Mean Porosity4 % (P4) [2]

Mean Porosity8 % (P8) [1]

Mean Porosity12 % (P12) [3]

Subtotal: 18 Injection Simulations

Stru

ctu

ral

Vari

abili

tyPr

op

erty

Var

iab

ility

Vertical Injection Wellwith Single Hydraulic Fracture

BHP42 MPa

Mean Thickness30 m (T30) [1]

Mean Thickness60 m (T60) [3]

Mean Perm.4 md (K4) [1]

Mean Perm.20 md (K20) [2]

Mean Perm.40 md (K40) [3]

Mean Porosity4 % (P4) [2]

Mean Porosity8 % (P8) [1]

Mean Porosity12 % (P12) [3]

Subtotal: 18 Injection Simulations

Horizontal Injection Well with Four Hydraulic Fractures

0

0.3

0.6

0.9

1.2

1.5

T30_K

4_P4

T30_K

4_P8

T30_K

4_P12

T30_K

20_P

4

T30_K

20_P

8

T30_K

20_P

12

T30_K

40_P

4

T30_K

40_P

8

T30_K

40_P

12

T60_K

4_P4

T60_K

4_P8

T60_K

4_P12

T60_K

20_P

4

T60_K

20_P

8

T60_K

20_P

12

T60_K

40_P

4

T60_K

40_P

8

T60_K

40_P

12

Mt C

O2/

yr

0

0.3

0.6

0.9

1.2

1.5

T30_K

4_P4

T30_K

4_P8

T30_K

4_P12

T30_K

20_P

4

T30_K

20_P

8

T30_K

20_P

12

T30_K

40_P

4

T30_K

40_P

8

T30_K

40_P

12

T60_K

4_P4

T60_K

4_P8

T60_K

4_P12

T60_K

20_P

4

T60_K

20_P

8

T60_K

20_P

12

T60_K

40_P

4

T60_K

40_P

8

T60_K

40_P

12

Mt C

O2/

yr

CO2 Injection Rate Averaged over 30 Years of Injection

Vertical Well (BHP=32 MPa)

Horizontal Well (BHP=32 MPa)Vertical Well Hydraulic Fracture (BHP=42)

Horizontal Well Hydraulic Fracture (BHP=42)

Vertical Well (BHP=40 MPa)

Horizontal Well (BHP=40 MPa)Vertical Well Hydraulic Fracture (BHP=42)

Horizontal Well Hydraulic Fracture (BHP=42)

0.00

2.50

5.00

7.50

10.00

12.50

15.00

17.50

20.00

22.50

25.00Vertical Well 32 MPa BHPVertical Well 40 MPa BHP

1.31

More Likely Less Likely

Ass

ocia

ted

Wel

l Cos

t US

$/t C

O2

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

3_T30

_K4_

P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

Vertical Well 32 MPa BHPVertical Well 40 MPa BHP

Reg

iona

l Are

a R

equi

red

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000Vertical Well 32 MPa BHPVertical Well 40 MPa BHP

Num

ber o

f Wel

ls R

equi

red

522

3_T30

_K4_

P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

3_T30

_K4_

P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

A.

B.

C.

0

2

4

6

8

10

12

14

16

18

20

0

650

1300

1950

2600

3250

3900

4550

5200

5850

6500

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

3_T30

_K4_

P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

More Likely Less Likely

Ass

ocia

ted

Wel

l Cos

ts U

S$/

t CO

2R

egio

nal A

rea

Req

uire

dN

umbe

r of W

ells

Req

uire

d

1.31

Vertical Well Hydraulic FractureEstimated VW Micro-seismicityHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic FractureEstimated HW Micro-seismicity

Vertical Well Hydraulic FractureHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic Fracture

Vertical Well Hydraulic FractureEstimated VW Micro-seismicityHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic FractureEstimated HW Micro-seismicity

A.

B.

C.3_

T30_K

4_P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

3_T30

_K4_

P8

4_T30

_K4_

P4

4_T30

_K20

_P8

5_T30

_K4_

P12

5_T60

_K4_

P8

5_T30

_K20

_P4

5_T30

_K40

_P8

6_T60

_K4_

P4

6_T30

_K20

_P12

6_T60

_K20

_P8

6_T30

_K40

_P4

7_T60

_K4_

P12

7_T60

_K20

_P4

7_T30

_K40

_P12

7_T60

_K40

_P8

8_T60

_K20

_P12

8_T60

_K40

_P4

9_T60

_K40

_P12

Average kH (permeability thickness), m3 X10-9

Not Feasible: Costs > Maximum Economic Threshold of 1.31 US$/t CO2

Likely Feasible: Costs Within the Range of Economic Thresholds of 0.875-1.31 US$/t CO2

Feasible: Costs < Minimum Economic Threshold of 0.875 US$/t CO2

Inje

ctio

n S

cena

rio

0.1 1 10

Vertical Well: 32 MPa BHP

Vertical Well: 40 MPa BHP

Horizontal Well: 32 MPa BHP

Horizontal Well: 40 MPa BHP

Vertical Well: Hydraulic Fracture

Horizontal Well: Hydraulic Fractures

Vertical Well: Induced Micro-seismicity

Horizontal Well: Induced Micro-seismicity

Econo

mic Tr

ansit

ion fo

r Thr

esho

ld of

1.31 U

S$/t C

O 2

Inje

ctio

n S

cena

rio

0.1 1 10

Vertical Well: 32 MPa BHP

Vertical Well: 40 MPa BHP

Horizontal Well: 32 MPa BHP

Horizontal Well: 40 MPa BHP

Vertical Well: Hydraulic Fracture

Horizontal Well: Hydraulic Fractures

Vertical Well: Induced Micro-seismicity

Horizontal Well: Induced Micro-seismicity

Econo

mic Tr

ansit

ion fo

r Thr

esho

ld of

1.31 U

S$/t C

O 2

Econo

mic Tr

ansit

ion fo

r Thr

esho

ld of

2.62 U

S$/t C

O 2

Econo

mic Tr

ansit

ion fo

r Thr

esho

ld of

3.93 U

S$/t C

O 2

EconomicallyFeasible

Not Economically Feasible

A.

B.

Average kH (permeability thickness), m3 X10-9

1900

2050

2200

2350

2500

2650

2800

0 20 40 60 80 100

Dep

th [m

]

Pressure [MPa]

Pp SvShmin SHmax

minifrac

Strike-SlipFrictionalFaulting

Equilibrium

TrentonLimestone

BeekmantownDolomite

Rose Run Ss.

Copper RidgeDolomite

Nolichucky Shale

Upper MaryvilleDolomite

Lower MaryvilleSandstone

1. Define the CO2 Sequestration Project and Goals

a. Characterize the Geology

b. Characterize the Geomechanics

3. Construct 3D Reservoir Model Using Geostatistics

4. Simulate CO2 Injection

5. Evaluate CO2 Injection and Sequestration Feasibility

7. Regional Sequestration Assessment

2. Regional Characterization

6. Evaluate Injectivity Enhancement Techniques for ImprovedCO

2 Sequestration Feasibility

- This assessment methodology is a tool for estimating regional effective CO2

sequestration capacity

- It considers: 1. Available aquifer storage volumes 2. Realistic well injection rates 3. The costs associated with drilling and maintaining injection wells

- It utilizes: 1. Geological Characterization 2. Geomechanical Characterization 3. Aquifer Modeling 4. CO

2 injection simulation

- Regions are evaluated at the scale of individual injection intervals that represent the heterogeneity and uncertainty of regional aquifer properties

- In regions with low-to-moderate permeability and aquifer thickness, the injectivity of an aquifer may severely limit its effective storage potential

- Aquifer stimulation techniques can increase injectivity and decrease costs

- Carrying out a geomechanical analysis at a proposed injection site is necessary for: 1. Controlling injection pressures 2. Formulating stable deviated well trajectories 3. Developing hydraulic fracture treatments 4. Characterizing existing hydraulically conductive fractures 5. Planning induced micro-seismicity treatments

- For CO2 sequestration to be practical in a large portion of the Midwestern

United States, stimulation techniques will need to be employed

- The permeability, k, and the thickness, H, are the primary properties controlling the injection rate

- Models are more likely to be economically feasible if they have large kH values and are stimulated with hydraulic fractures or induced micro-seismicity

- At a higher cost per ton of CO2, some

models with smaller kH values and less stimulation become economically feasible

- With simple vertical or even horizontal injection wells, the region is unlikely to have enough injection capacity to make CO

2 sequestration feasible

- The Rose Run region meets the spatial requirements for sequestering 113 Mt CO

2/yr for 30 years.

- The Rose Run region is likely a feasible location for CO2 sequestration

- Several areas of investigation will lead to a more complete assessment 1. Characterize the stress state at more locations 2. Find trends in aquifer thickness and permeability to optimize kH values 3. Injection induced micro-seismicity experiments to determine the potential for increasing injectivity in the region

The goal of this project is to sequester 90% of the emissions from the 23 power plants near the case study area for 30 years at the current emissions rate of 126 Mt CO

2/yr (i.e.

113 Mt CO2/yr or 3.39 Gt CO2 over 30 years)

The economic constraints limit the costs associated with drilling and maintaining the injection wells in the region to ideally less than 0.875 US$/t CO

2 but up to 1.31 US$/t

CO2 (based on regional cost of energy and emissions rates)

The associated well costs are estimated by the type of well, stimulation techniques, and maintenance costs for the lifetime of the well

Study Area:- Rose Run is 2350±100 m deep (36 km X 360 km) - Corresponds to the depth of the Rose Run at the Mountaineer power plant - Near 23 large point sources, which emit approximately 126 Mt CO

2/yr

Well Type Initial Cost

(M US$)

Lifespan (years)

Annual Maintenance Cost (M US$)

Total Well Cost

(M US$)

Maximum # of Wells

Vertical well 4.0 30 0.15 8.5 522

Vertical well with hydraulic fracture 4.5 30 0.15 9.0 493

Vertical well with induced micro-seismicity 5.5 30 0.15 10.0 444

Horizontal well 6.0 30 0.15 10.5 423

Horizontal well with 4 hydraulic fractures 7.5 30 0.15 12.0 370

Horizontal well with induced micro-seismicity 8.5 30 0.15 13.0 342

The mean thickness of the Rose Run is about 30 m, but in some areas it can be more than 60 m thick

We defined three lognormal porosity distributions to evaluate with mean porosity values of 4%, 8%, and 12%.

We modeled three multigaussian log permeability distributions: (1) ranging from 1.6-25 md and a mean of about 4 md, (2) ranging from 8-125 md with a mean of about 20 md, and (3) ranging from 16-250 with a mean of about 40 md.

5 10 15 20 25 30

Porosity [%]

1 10 100 1000

Permeability [mD]

NWe modeled two aquifer thicknesses 1. Averaging 30 m (varying from 15 to 50 m) 2. Averaging 60 m (varying from 45 to 80 m)

We modeled each aquifer thickness three times: 1. Without a hydraulic fracture 2. With a single hydraulic fracture 3. With four, smaller, staggered hydraulic fractures that represent hydraulic fracturing along a horizontal well.

We populated the models with porosity and permeability values using sequential Gaussian simulation with 9 possible property combinations 1. Mean porosity = 4%, 8%, or 12% 2. Mean permeability = 4 md, 20 md, or 40 md

A. CO2 saturation after 30 year of injection for the six

injection scenarios that are simulated

B. Cumulative CO2 injection over 30 years for the six

scenarios

Stress magnitudes at the Mountaineer Site. The minifrac tests (red) indicate that the S

hmin magnitude

has two trends. It is significantly less in the Rose Run than that above and below. This means hydraulic fracturing is feasible.

Sv=62SHmax=54Shmin=34Pp=Pm=26

TENDENCY FOR BREAKOUTS AT 2365 m DEPTH

Stress Magnitudes [MPa]

Rose Run:Normal Faulting Stress Regime

Rock Strength [MPa] to Prevent Breakouts with >30o Width

SHmax

65 70 75 80 85 90

N

Horizontal Wellin Shmin Direction

Vertical Well

Well trajectories with hot colors require higher rock strengths to prevent breakouts and are therefore less stable. The Rose Run rock strength is more than 200 MPa at the Mountaineer site, so all well trajectories are stable the Rose Run stress state.

Fractures in the Rose Run sandstone. The lower hemisphere stereonet plot indicates likelihood of fault slip as a function of pole to the fracture plane. Fractures are also plotted on a Mohr diagram. Critically stressed faults often act as conduits for flow and enhance permeability. The presence of critically stressed faults make induced microseismicity a feasible stimulation technique.

Outline of fluid flow simulations, organized by injection scenario. BHP is bottom hole pressure used to constrain injection rates, and is constrained by S

hmin. The

abbreviations in ( ) refer to the naming convention. The number in [ ] categorizes the likelihood of a property to be found in the region, [1] is most and [3] is least likely.

CO2 injection rate averaged over 30 years

of injection. Simulations are sorted in order by thickness (T30, T60), permeability (K4, K20, K40), and porosity (P4, P8, P12).

Injection interval models are ranked by their likelihood of occurring in the region basedon their hydrogeological property values 1. We added up the values (1-3) for the 3 properties to get a ranking value from 3 to 9 2. Models with lower values are more representative of the regional aquifers 3. The ranking values are appended to the beginning of the model names.

We examined whether the sequestration goals could be met honoring spatial constraints 1. We calculated the surface area of the top of the CO

2 plume after 30 years of injection

2. Determined how many injection wells would be necessary to inject 113 Mt CO2/yr 3. We calculated the percentage of the regional area required to reach the goal 4. All of the potential injection scenarios met the spatial feasibility constraint.

We determine if economic constraints could also be honored (i.e., the sequestration goal is met with fewer than 522 vertical wells or an associated well cost of less than $1.31/t CO2) 1. For a BHP of 32 MPa, 3 models with ranking values > 6 honor the constraint 2. For a BHP of 40 MPa, 10 models honor the constraint, 4 of these have a ranking value of 5 or 6 (moderately likely) 3. It is unlikely that the study area contains enough sites similar to these models to meet its sequestration goals using only vertical injection wells.

We showed that injection scenarios such as using horizontal wells, hydraulically fracturing vertical or horizontal wells, and induced micro-seismicity within the aquifer were all feasible ways to increase injection rates However, these potential increases in injection rates come with higher associated well costs.

All of the enhanced injectivity scenarios honor the regional spatial constraints

We determine if the economic constraints could also be honored 1. In induced micro-seismicity cases we assumed that the injection rate was five times that of the vertical or horizontal wells simulated with a 40 MPa BHP 2. The number of wells required to sequester 113 Mt CO

2/yr was estimated for

the 6 potential injectivity enhancement techniques 3. When the number of wells was translated into associated well costs per ton of CO

2, 15 of the 18 models had at least one injection scenario that was

within the feasibility threshold of 1.31 US$/t of CO2.

4. Horizontal wells alone do not reduce the costs enough to be economical 5. Injection wells with hydraulic fracturing and/or induced micro-seismicity increases the likelihood that Rose Run sequestration goals can be reached.

Pp is pore pressure, S

hmin is the minimum horizontal

compressive stress, SHmax

is the maximum horizontal compressive stress, S

v is the vertical stress

Ohio

Indiana

West Virginia

Kentucky

87° W 85° W 83° W 81° W 79° W 37° N

38° N

39° N

40° N

41° N

42° N

Earthquake Magnitude2 43 5

CO2 Emissions [Mt/yr]0.5 51 10

Ohio River

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