A Comprehensive Deterministic Petrophysical Analysis Procedure for Reservoir Characterization: Conventional and Unconventional Reservoirs 2014 RMS-AAPG.

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A Comprehensive Deterministic Petrophysical Analysis Procedure for Reservoir Characterization: Conventional and Unconventional Reservoirs 2014 RMS-AAPG Luncheon, Oct 1 st, Denver, CO Presented by: Michael Holmes, Antony Holmes and Dominic Holmes Digital Formation, Denver, Colorado, 2014 Slide 2 Outline Introduction Conventional and Unconventional reservoir petrophysical models Procedures 1. Standard shaley formation petrophysical model 2. Unconventional reservoir petrophysical model Four porosity components model TOC calculations Standard vs. shale only density/neutron comparisons Free and adsorbed hydrocarbons Slide 3 Outline Procedures Cont. 3. Fracture analysis 4. Relative permeability model 5. Rock physics model and mechanical properties brittle vs. ductile 6. Comprehensive petrophysical model Examples Niobrara, Colorado Barnett Shale, Texas Antrim Shale, Michigan Shale Gas, Western Canada Bakken, Montana Tight Gas, Colorado New Albany, Illinois Slide 4 Introduction Conventional vs. unconventional reservoir petrophysical models Shale MatrixEffective Porosity WaterOil/Gas The Reservoir Conventional Reservoirs Slide 5 *Note: Components not to scale Free Shale Porosity Phi FS Water Adsorbed Hydrocarbon ? Water Free Hydro- carbons ? Water Total Organic Carbon-TOC Free Hydro- carbons Bound Water Free Water Four Porosity Components Solids Effective Porosity Phi e Non Shale Matrix Silt Clay Solids Introduction Unconventional Reservoirs Slide 6 Procedures In the following discussions an example from the Niobrara (Colorado) is used to illustrate procedures Slide 7 Procedures 1 Standard Shaley Formation Analysis Raw Data Shale Matrix Porosity Fluids Grain Density Bulk Fluid Volumes LithologyPayR WA Perm Core data symbols/heavy line Slide 8 Procedure 2 Unconventional Reservoir Petrophysical Model Four Porosity Component Model TOC Phi Components Phi e e FS Phi Clay TOC Phi e e Clay Phi FS Slide 9 TOC Calculation TOC Passey et al Responses in Organic lean intervals Hot colors indicate increasing TOC Note Mismatch Comparison of core TOC (Illustrated by thick black line) with petrophysically determined TOC from each porosity log TOC = Total Organic Carbon Slide 10 TOC Calculation TOC Schmoker Schmoker has three different correlations of RhoB with TOC: High Appalachian correlation Low Appalachian correlation Williston Basin Bakken Note Mismatch Slide 11 Regular Density/Neutron Cross Plot Calculations are: Total porosity Phi t Shale volumeV SH Effective porosity Phi e Matrix volumeV ma Fluid saturation in effective porosity oil, water, gas Our preference is to use a density/neutron cross plot for total porosity, to minimize influences of changing matrix and fluid properties Slide 12 Shale Only Density/Neutron Cross Plot Slide 13 Free Shale Porosity and Free Available Porosity Free Shale Porosity = Total Porosity Effective Porosity Clay Porosity Free Available Porosity = Free Shale Porosity + Effective Porosity Clearly free shale porosity is zero or greater. If negative values are calculated it might be a consequence of incorrect estimates of TOC, an incorrect assumption of TOC density, or an incorrect calculation of shale volume. Free Shale Porosity Phi FS Slight Mismatch Slide 14 Free vs. Adsorbed Hydrocarbons Free hydrocarbons are located in the free available porosity element, and are calculated using standard approaches Publications on calculating adsorbed hydrocarbon volumes are sparse. Empirical relations are: Gas Published Relation Adsorbed G.I.P. (SCF) = 1359.7 X Area X Thickness X RhoB X (16 X TOC) Oil Suggested Relation Adsorbed O.I.P. (Bbl) = S2 X 0.0007 X RhoB X h X Area X 7758 S2 = Hydrocarbons generated by thermal cracking Slide 15 Procedure 2 Unconventional Reservoir Petrophysical Model Shale Formation Clean Formation Raw Data 1Gr, SP4Saturations7Porosity Comparison 10Net Pay Shale13Porosity Comparison 2Porosity5Bulk Volumes8Permeability11Shale Model14TOC Comparison 3Resistivity6Lithology9Net Pay Clean12Porosity Comparisons 1234567891011121314 Slide 16 Procedure 3 Fracture Analysis from Standard Open-Hole Logs The methodology involves examining rates of change of curve magnitude with depth Criteria are established by the interpreter for abnormally rapid change If the change to higher porosity is deemed to be too rapid for normal sedimentary processes, then open fractures are suggested If the change is to lower porosity, closed (healed) fractures are suggested Results can be compared with image logs, and there is usually quite good comparison with this petrophysical methodology Calculations involve all available logs Porosity Resistivity Calculated Matrix Curves Caliper Density Correction Slide 17 Fracture Analysis Example Individual Log Responses Stacked Data Pink O = Open Fractures ? Low stress Blue C = Closed Fractures ? High stress Note Fracture concentration in Niobrara C and Ft. Hays Slide 18 Procedure 4 Relative Permeability Model Slide 19 Relative Permeability Example Oil Well Relative Permeability Effective Permeability Fluid VolumeReservoir Components Pay Flag Water/Oil Ratio Slide 20 Relative Permeability Example Gas Well Relative Permeability Effective Permeability Fluid VolumeReservoir Components Pay Flag Water/Gas Ratio Low water adjacent to pay High water adjacent to pay Slide 21 Procedure 5 Rock Physics Model and Mechanical Properties Brittle vs. Ductile To calculate mechanical properties, the following measurements are required Acoustic compressional Acoustic shear Density Often acoustic shear is not available but can be estimated from other logs. The example shows pseudo curves based on the Krief geophysical model (Dipole Sonic not run in the Niobrara example). Dipole Sonic Slide 22 Rock Physics Model and Mechanical Properties Raw Log DTDTS/DTDTSDensityNeutron Slide 23 Youngs Modulus vs. Poissons Ratio Brittle Ductile Slide 24 Procedure 6 Comprehensive Petrophysical Model 1 2 3 4 5 6 7 8 9 10 11 1.Fluid Saturation4.Permeability7.Water/Oil Ratio Oil Reservoirs Water Bbl per MMCF Gas Reservoir 10.Porosity Types Phie and shale porosity 2.Bulk Volume non shale fraction 5.Pay Flag Clean Formation Yellow = Gross Sand Red = Net Sand Green = Pay 8.Brittle vs. Ductile11.Porosity Types Free Shale Porosity and TOC 3.Lithology6.Pay Flag Shale Yellow = Gross Sand Red = Net Sand Green = Pay 9.Fractures A Standard Template is Used for All Examples Clay Porosity Slide 25 Niobrara, Colorado Oil Fractures in Niobrara & Ft. Hays Variable free shale porosity Niobrara benches are brittle Niobrara shales are ductile Very little shale contribution Fair to good core/log Correlation Clay Porosity Slide 26 Bakken, Montana Oil Very high TOC Water production from lower Three Forks High free shale porosity Clay Porosity Slide 27 Barnett, Texas Shale Gas Zone 1 4 Shale Higher free shale porosity than zone 5 Good correlation core/logs Shales show variable ductile/brittle responses Slide 28 Antrim, Michigan Shale Gas Pay contribution from most of the shales High TOC and free shale porosity Shale shows variable brittle/ductile responses Fractures sporadic Good correlation core/logs Slide 29 Western Canada Shale Gas Good correlation core/logs Major contribution from shales Shales are entirely brittle High values of free shale porosity Slide 30 Piceance Basin, Colorado Tight Gas Very low TOC and free shale porosity Sand intervals are brittle Minor shale contribution Fractures common Clay Porosity Slide 31 Bakken, North Dakota High free shale porosity and TOC in both shale intervals Oil-in-place in shale: 10.2 MMBO per 640 acres Carbonate: 9.6 MMBO per 640 acres Clay Porosity Slide 32 New Albany, Illinois Good correlation Core/Log Clay Porosity Slide 33 References Michael Holmes, Antony Holmes, and Dominic Holmes A Petrophysicial Model to Estimate Free Gas in Organic Shales, Presented at the AAPG Annual Convention and Exhibition, Houston Texas, 10-13 April, 2011. Michael Holmes, Antony Holmes, and Dominic Holmes A Petrophysical Model for Shale Reservoirs to Distinguish Macro Porosity, Micro Porosity, and TOC, Presented at the 2012 AAPG ACE, Long Beach, California, April 22-25. Holmes, Michael, et al. "Pressure Effects on Porosity-Log Responses Using Rock Physics Modeling: Implications on Geophysical and Engineering Models as Reservoir Pressure Decreases." Prepared for the SPE Annual Technical Conference and Exhibition held in Dallas, Texas, USA, 9-12 October (2005). Michael Holmes, Antony Holmes, and Dominic Holmes Petrophysical Rock Physics Modeling: A Comparison of the Krief And Gassmann Equations, and Applications to Verifying And Estimating Compressional And Shear Velocities presentation at the SPWLA 46 th Annual Logging Symposium held in New Orleans, Louisiana, United States, June 26-29, 2005 James W. Schmoker Use of Formation-Density Logs to Determine Organic-Carbon Content in Devonian Shales of the Western Appalachian Basin and an Additional Example Based on the Bakken Formation of the Williston Basin, Petroleum Geology of the Black Shale Eastern North America 1989. Q.R. Passey, S. Creaney, J.B. Kulla, F.J. Moretti, and J.D. Stroud A Practical Model for Organic Richness from Porosity and Resistivity Logs, AAPG 1990.