Geologic and Reservoir Characterization and Modeling

Transcription

1 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

2 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

3 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

4 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 φ, % k, md CCS #1

5 Petrophysical Challenge: Permeability-Porosity Core Data Core Permeability n Porosity alone is not a good predictor of permeability Core Porosity CCS #1

6 Petrophysical Characterization: Core φ-k Transform Based on Grain Core Permeability 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? Core Porosity CCS #1

7 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

8 Geologic Characterization: Permeability Transform based on m Injection Well (CCS #1) Injection Well: Worked well with laterolog Low invasion mud used Verification Well: Different mud used and use of laterolog failed Use of induction logs improved the match, but under-predicted high permeability values Depth K (md) Dark blue line: predicted permeability using m Pink squares: rotary sidewall core plug permeability

9 Geologic Characterization: Net Thickness Gross and Net Thickness: Porosity Cutoffs 6100 Depth (ft) % 12% 10% 14% CCS #1 Porosity What fraction of the gross thickness of the Mt. Simon has storage and injectivity?

10 Geologic Characterization: Gross and Net Thickness Porosity Cutoff, % 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 ft 578 ft

11 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

12 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

13 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

14 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

15 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%

16 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

17 Reservoir Model n Gridding n Calibration n Simulations n Plume management n Pressure management

18 * 2-10 ft layers at injection zone Reservoir Model: Vertical Gridding Depth (ft) Coarse Medium Fine Ultra Fine Model Porosity # of Layers h layer ft Coarse Medium Fine * Ultra Fine 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

19 Reservoir Model: Gridding n Example: n 108 layer model n Permeability (log 10 ) n 2 miles x 2 miles by ft n Granite wash included

20 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

21 Reservoir Model: Water Pressure Transient Test Partial Penetration/Completion Model UNIT S L P ENDWBS PPNSTB Delta- T (hr) SPHERE 2009/10/ : OIL S TABIL n k h 185 md n k v 2.45 md n k v /k h (over 75 ft interval) Partial Penetration Well

22 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 k v, md h, ft 78 75

23 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

24 Reservoir Simulation: Plume Management Example Single Perforated Interval: Year 1 Upper Perforated Interval: Year 2

25 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

26 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

27 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

28 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