Geologic and Reservoir Characterization and Modeling Scott M. Frailey and James Damico Illinois State Geological Survey Midwest Geologic Sequestration Science Conference November 8 th, 2011
Acknowledgements n n 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) and by a cost share agreement with the Illinois Department of Commerce and Economic Opportunity, Office of Coal Development through the Illinois Clean Coal Institute. Landmark Graphics Software Donation via University Program and Schlumberger Carbon Service for technical support and consultation
Modeling Goal n To develop a representative reservoir model based on geology, petrophysical, and fluid properties to provide guidance to n Pilot design n Active CO 2 injection operations n Long-term sequestration strategies n Specifically n Plume shape, size, and distribution n Far-field pressure magnitude and distribution
Petrophysical Challenge: Predicting Permeability n Permeability is a function of porosity and packing arrangement/grain size n Cores with similar porosity can have significantly different permeability values Depth, ft MD 6763 7045 φ, % 28.5 28.6 k, md 43.2 1440 CCS #1
Petrophysical Challenge: Permeability-Porosity Core Data Core Permeability 10000 1000 100 10 1 0.1 n Porosity alone is not a good predictor of permeability 0.01 0.001 0.0001 0 5 10 15 20 25 30 Core Porosity CCS #1
Petrophysical Characterization: Core φ-k Transform Based on Grain 10000 1000 Core Permeability 100 10 1 0.1 0.01 0.001 Size n Sub-divide core data by grain size category n Better representation of the core data n How to pick transform based on log response? 0.0001 0 5 10 15 20 25 30 Core Porosity CCS #1
Petrophysical Characterization: Core φ-k Transform Based on Grain Size n Grain size correlated to Archie s cementation exponent m n Resistivity and porosity logs n In-situ brine resistivity n m correlated to grainsize based φ-k transforms Schwartz and Kimminau, 1987
Geologic Characterization: Permeability Transform based on m 5500 5700 Injection Well (CCS #1) Injection Well: Worked well with laterolog Low invasion mud used 5900 6100 6300 Verification Well: Different mud used and use of laterolog failed Use of induction logs improved the match, but under-predicted high permeability values Depth 6500 6700 6900 7100 0.001 0.01 0.1 1 10 100 1000 10000 K (md) Dark blue line: predicted permeability using m Pink squares: rotary sidewall core plug permeability
Geologic Characterization: Net Thickness 5500 5600 5700 5800 5900 6000 Gross and Net Thickness: Porosity Cutoffs 6100 Depth (ft) 6200 6300 6400 6500 6600 6700 6800 6900 7000 8% 12% 10% 14% 7100 0.05 0.10 0.15 0.20 0.25 0.30 CCS #1 Porosity What fraction of the gross thickness of the Mt. Simon has storage and injectivity?
Geologic Characterization: Gross and Net Thickness Porosity Cutoff, % 0 8 10 12 14 Gross Injection Well Net Thickness 1505 ft 1322 ft 1009 ft 744 ft 569 ft Gross Verification Well Net Thickness 1476 ft 1344 ft 1064 ft 782.5 ft 578 ft
Geologic Model: Objectives n Integrate petrophysical characteristics and conceptual geologic model n Approximate the geologic architecture for gridded reservoir simulation models n Develop multiple models based on reasonable geologic and petrophysical interpretations
Geologic Model: Monte Carlo Method n n Random generation of petrophysical properties using probability functions Generate numerous models quickly, but with little regard to geologic architecture
Geologic Model: Architecture and Facies Both systems have same proportion of high permeability facies Structured System: black are connected across model edges Random System: black not connected across model edges Higher Permeability Facies Guin and Ritzi, 2008, Geophys. Res. Ltrs., (L10402) Lower Permeability Facies
Geologic Model: Petrophysical Properties Linked to Facies n Geostatistics well established for modeling facies geometry for specific geologic environments n Important to populate the geostatistically generated facies with petrophysical properties
Geologic Model: Plurigaussian Simulation n Grain size (m) used as a proxy for facies n Maintains hierarchical relationships between facies Coarse: 38.3% Coarse-Medium: 6% Medium: 6.5% Medium-Fine: 6.1% Fine: 43.2%
Geologic Model: Plurigaussian Simulation Facies (grain size) model Next facies models n geophysics and geologist interpretation to build true facies model n Mt. Simon outcrop study planned to improve facies interpretation
Reservoir Model n Gridding n Calibration n Simulations n Plume management n Pressure management
* 2-10 ft layers at injection zone Reservoir Model: Vertical Gridding Depth (ft) 5500 5600 5700 5800 5900 6000 6100 6200 6300 6400 6500 6600 6700 6800 6900 7000 Coarse Medium Fine Ultra Fine Model 7100 0.05 0.10 0.15 0.20 0.25 0.30 Porosity # of Layers h layer ft Coarse 6 250 Medium 28 53 Fine 108 15* Ultra Fine 322 5 n Grid Selection: n Honor geologic architecture and facies n Understand geologic features influencing flow n Select grid to model these features n Grids chosen for computational reasons: for general guidance only
Reservoir Model: Gridding n Example: n 108 layer model n Permeability (log 10 ) n 2 miles x 2 miles by 1400-1500 ft n Granite wash included
Reservoir Model: Pre-CO 2 (Water) Calibration n CCS#1 Water Injection Pressure Transient Test n 25 ft perforated interval (injection/falloff, steprate test) n 25 ft + 30 ft perforated (injection/falloff) n Injection spinner logs infer no water injection into upper perfs
Reservoir Model: Water Pressure Transient Test 10-3 10-2 10-1 Partial Penetration/Completion Model UNIT S L P ENDWBS PPNSTB 10-3 10-2 10-1 10 0 10 1 Delta- T (hr) SPHERE 2009/10/01-2229 : OIL S TABIL n k h 185 md n k v 2.45 md n k v /k h 0.013 (over 75 ft interval) Partial Penetration Well
Comparison of Water PTA and Transformed Permeability n k h estimated every 0.5 ft n k v /k h of 0.85 used every 0.5 ft for k v n Harmonic average (series flow) used to calculate k v over 75 ft interval. Log/ Core PTA k h, md 182 185 k v, md 2.43 2.45 h, ft 78 75
Reservoir Simulation Pilot Design Applications Plume Management n n Location of verification well UIC permit specifications Pressure Management n Equipment and hardware n n Injection equipment selection (centrifugal pump) Maximum pressure ratings (valves and gauges) Plume and Pressure Management n Injection wellbore n n Perforation interval selection Location of the packer in the injection well
Reservoir Simulation: Plume Management Example Single Perforated Interval: Year 1 Upper Perforated Interval: Year 2
Reservoir Simulation: Pressure Management Example n Bottomhole injection pressure compared to fracture pressure n Pore pressure below caprock and intermediate seals compared to capillary entry pressure n Far-field pressure and regulated area of review and pressure thresholds
Conclusions n Unique method used to transform core permeability to well log porosity n Realistic geologic model based on facies and architecture n facies model populated with petrophysical properties n Water injection validated geologic model of injection zone n good agreement between core, logs and PTA
Conclusions, contd. n Model development n Objective and data driven n Not model driven n Model limitations and applications n Geologic and petrophysical uncertainty n Specific models not appropriate for all tasks n Realistic expectations of reservoir models
Geologic and Reservoir Characterization and Modeling Scott M. Frailey and James Damico Illinois State Geological Survey Midwest Geologic Sequestration Science Conference November 8 th, 2011