Assessing the Significance of an Injection Pilot: Implications on a Commercial Storage Project Scott M. Frailey, PhD, PE llinois State Geological Survey Research Institute of Innovative Technology for the Earth CCS Technical Workshop January 22, 2017 www.gsco2.org www.sequestration.org
■ The Midwest Geological Sequestration Consortium is funded by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) via the Regional Carbon Sequestration Partnership Program (contract number DE-FC26-05NT42588). The Midwest Geological Sequestration Consortium (MGSC) is a collaboration led by the geological surveys of Illinois, Indiana, and Kentucky Landmark Graphics Software Donation via University Program and Schlumberger Carbon Service for technical support and consultation ■ ■
■ Answer the simple, logical question: “Do we need a pilot CO, injection project prior to our planned large scale injection?” ■ Infer the “value” of a pilot project to a commercial-scale project
■ A commercial scale storage site is planned ■ Site is selected based on rigorous regional screening studies ■ Design of the site to include flexibility of a short term, small CO2 mass injection pilot preceding financial commitment of a commercial scale project at the site.
■ Pre-drill: pilot  and well planning ■ Pilot ■ Geologic and Petrophysical Characterization ■ Injection rate and pressure ■ Water ■ CO, ■ Microseismicity ■ Pilot to a Commercial Project
Site selected, no well, no seismic over area Regional geology, “nearby” well data available Pre-Drill: Competitive uses, data sources, and availability ■ Industrial uses ■ Natural gas storage ■ No minerals present ■ Many wells, but focused in very small areas (natural gas storage field) ■ Two major oilfields with deep “basement” tests Pre-Drill: Competitive uses, data sources, and availability, contd. ■ In sub-basin area of interest, 1 well drilled to crystalline basement. More wells in caprock and upper sub-interval ■ Single porosity log, a simple “basement” test prior to selling the property ■ Very little core or core data ■ No seismic data over the area Pre-Drill: Regional Geology ■ Pervasive thick clastic ■ Overlying confining unit: ■ thick clay rich shale ■ Underlying confining unit: ■ crystalline basement (granite and rhyolite) Illinois Basin- Decatur Test Site ■ A Dehydration/ compression facility location ■ B Pipeline route ■ C Injection well site D Representative verification well sites Quickbird Satellite Image: 9/16/ 2008 Pre-Drill:
■ Two wells 35-50 miles from site ■ 150-200 ft clay rich cap rock ■ 1000+ ft of clastic injection interval ■ 8-10% porosity over gross interval ■ 15-20% porosity subinterval at the base ■ One site upper most sub-interval used for natural gas storage. Pre-Drill: Pilot Injection Well Description ■ Single well injection ■ Perforated low in the stratigraphic unit ■ Monitoring well ■ Multiple sampling (fluid and pressure) depths
■ Injection ■ Rates: Maximum and operational ■ Injection pressure: regulated and operational ■ Distribution of CO, ■ Vertical ■ Lateral ■ Storage Capacity and Resource

■ Well
■ TD: drill to 100+ feet below clastic-crystalline basement contact) ■ Diameter: ■ “Manageable” pressure drop in injection tubing ◾ “Geophones” deployed in annulus ■ Concentric casing in upper part of caprock
■ Core ■ Full diameter: ■ First well: Minimal due to poor depth control ■ Second well: 100s ft based on logs of first well ■ RSWC-numerous to compliment whole core and well site interpretation of logs ■ Open hole well logs Pilot Well: Geologic and Petrophysical Characterization Post-drill, pre-CO2 injection Two wells drilled
■ Logs:  Laterolog, lithodensity, neutron, spectral gamma ray, fullwave sonic, magnetic resonance, FMI ■  Core:  Sidewall Rotary and Whole Core ■ Routine porosity and perm:  Vertical and horizontal ■ Mechanical Strength ■ Electrical resistivity ■ Capillary pressure ■ Effective perm to gas ■ T2 ■ Petrography: thin sections, SEM/XRD ■ Seismic: 3d-Surface and 3d-VSP Pilot Well Characterization: Summary ■ Age:  Cambrian ■ Depositional System:  braided river system ■ Depth: 5405 – 7165 ft ■ Gross Thickness: 1620 ft ■ Average Total Porosity: 13.4% ■ Average Absolute Perm (transformed): ■ kh 26.4 md; kvarth 22.4 md; kvharm 0.0482 md ■ Pressure: 3206 psig ＠ 7045 ft (0.455 psi/ft) Pilot Well Characterization: Porosity and Permeability ■ Challenge relating porosity and permeability
Neutron-Density Porosity Gross and Net Thickness: Porosity Cutoffs Thieknocc
Pilot Well Characterization: Gross and Net Thickness
■ Depth Shift: core to log ■ Transform core porosity to core permeability ■ Conventional semilog plot not good predictor of perm Pilot Well Characterization: φ-k Transform Based on Grain Size ■ Sub-divide data by grain size ■ Better representation of the core data ■ How to pick transform based on log response? kh Comparison kh = 6700 md-ft (25 ft injection zone)
Courtesy J. Damico, 2018 0.0001 0.01 0.001 10 100 .1000 10000 Pilot Well: Injection Rate and Pressure Post-drill, pre-CO, injection Water injection test into planned CO, injection well Completion Plan: Pre-CO₂, Water Injection Test ■ Treated water test for fracture gradient, permeability-thickness, pressure, geologic features (influencing pressure), and skin ■ Perforate 25 ft (consecutive) of highest permeability and porosity (log and core) ■ Test for injection rate-pressure response and fracture gradient Completion Plan: Pre-CO₂, Water Injection Test, contd. ■ Backup plan: additional 30 feet of perforations, about 10 vertically upward from lower 25 ft. Pilot Well Characterization: Injection Sub-interval Test ■ Single Well Water Injection Pressure Transient Test ■ 25 ft perforated interval (Injection/falloff, step- rate test) ■ 25 ft + 30 ft perforated (injection/falloff) ■ Injection spinner logs infers no water injection into upper perfs
ADM CCS #1 Step Rate Test 7025-7050
Partial penetration effect (-1/2 slope) Pilot Well: CO, Injection Rate and Pressure Three years of “continuous” CO, injection at 1,000 tpd with operational interruptions due to routine maintenance.
■ Pilot rates ■ 1,000-1,100 tpd and Δp 300-400 psi ■ 2.5-3.2 tpd/psi ■ Regulated 80% of fracture gradient ■ Δp = 950 psi ■ 2,375-3,000 tpd CO₂ Injection: CO₂ Falloffs
Pilot Well: Microseismicity Measurements Three years of “continuous” CO, injection at 1,000 tpd with operational interruptions due to routine maintenance. R. Bauer et al., 2016 (next four slides)
Square: 2000 ft x 2000 ft Red symbol: Injection well location
0 2000 Feet From Injection Well 6000000000 8000  10000 12000 4000 14000
Precambrian crystalline basement
Depth thru Time Pilot to Commercial Project
Commercial Project: Design Elements ■ Injection rate: Average and peak ■ Injection pressure: bottomhole and surface ■ Induced seismicity ■ Area of CO, plume ■ Pilot ■ Existing plume and pressure ■ Surface facilities ■ Monitoring infrastructure Commercial Project: Pre-Drill - Well Location ■ Compressor and pipeline ■ Land and storage right ownership ■ Pilot infrastructure location and use ■ Injection well, monitoring well, and geophysical well ■ Subsurface ■ Geologic and petrophysical characterization ■ Pilot: plume, pore pressure, and stress field
Commercial Project: Pre-Drill - Wellbore ■ Depth: ■ Variability in crystalline basement topography ■ Caprock thickness and composition ■ Above seal, loss circulation zone
North Subsea depths (ft) Courtesy H. Leetaru 2018 Injection interval CCS2 (170+ ft) Injection interval CCS1 (25 ft, 30 ft)
Commercial Project: Post-Drill and Test - Completion ■ Perforation height: ■ permeability-thickness product ◾ injection rate ■ Location: ■ Seismicity (crystalline basement) ■ Caprock/seal interaction Commercial Project: Post-Drill and Test - Completion ■ Perforation height: ■ 173 ft perforated ■ kh = 6275 md-ft ■ Location: ■ 300+ ft above crystalline basement ■ ~1200 ft below caprock ■ No attempt to “breakdown” (open) perfs prior to testing
4100 psi (DHP) at 6 bpm (8,640 bpd)
Step Rate Test, PFO analyses, and spinner tests less than ideal data.  All strongly suggest perforations open changing from initially 10-20 ft open up to 35 ft near end of test...out of 173 ft perforated.
-BHP  ——BHT
Commercial Project: Injectivity Comparison ■ Initial pressure: 0.45 psi/ft ■ Fracture pressure: 0.71 psi/ft ■ Regulated pressure: 0.56 psi/ft ◾ Injection pressure 0.21 psi/ft ■ 210 psi per 1000 ft (0.56 - 0.45 psi/ft) ■ Δp: ■ CCS1 - 350 psi; (~1600 psi max) ■ CCS2 - 1000 psi; (~1550 psi max) CO₂ Injection: Monitoring ■ Seismicity Graph

■ Injection rate
■ Constant rate injection possible because injection pressure below maximum pressure ■ Pressure ■ CO, requires much lower injection pressure than predicted

■ Rate-Pressure
■ Clear and predictable relationship ■ Perforated interval ■ Logistics and economic reasons to “over” perforate ■ Operational and injectivity reasons to perforate much less

■ Seismicity
■ Basal formations susceptible to seismicity ■ Upper formations less susceptible to no seismicity Assessing the Significance of an Injection Pilot: Implications on a Commercial Storage Project Scott M. Frailey, PhD, PE llinois State Geological Survey Research Institute of Innovative Technology for the Earth CCS Technical Workshop January 22, 2017 www.gsco2.org www.sequestration.org