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2014 RMS-AAPG Luncheon, Oct 1st, Denver, CO
A Comprehensive Deterministic Petrophysical Analysis Procedure for Reservoir Characterization: Conventional and Unconventional Reservoirs 2014 RMS-AAPG Luncheon, Oct 1st, Denver, CO Presented by: Michael Holmes, Antony Holmes and Dominic Holmes Digital Formation, Denver, Colorado, 2014
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Outline Introduction Procedures
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
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Outline Procedures Cont. Examples 3. Fracture analysis
4. Relative permeability model 5. Rock physics model and mechanical properties β 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
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Conventional Reservoirs
Introduction Conventional vs. unconventional reservoir petrophysical models Conventional Reservoirs Shale Matrix Effective Porosity Water Oil/Gas The Reservoir
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Unconventional Reservoirs
Introduction Unconventional Reservoirs Free Shale Porosity PhiFS Water Adsorbed Hydrocarbon ? Free Hydro-carbons Total Organic Carbon-TOC Free Hydro-carbons Bound Water Free Water Clay Fluids ππ‘π’ ππ₯ππ² Total Porosity ππ‘π’ π ππ‘π’ π Four Porosity Components π ππ π π¦πππ«π’π± Solids Effective Porosity Phie Non Shale Matrix Silt Clay Solids *Note: Components not to scale
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Procedures In the following discussions an example from the Niobrara (Colorado) is used to illustrate procedures
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Procedures 1 β Standard Shaley Formation Analysis
Shale Matrix Porosity Bulk Fluid Volumes Grain Density Raw Data Fluids Lithology Pay RWA Perm Core data symbols/heavy line
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Procedure 2 β Unconventional Reservoir Petrophysical Model
Four Porosity Component Model The goal is to calculate the four porosity components from the unconventional reservoir model Effective Porosity Phi e Total Organic Carbon TOC Clay Porosity Phi Clay Free Shale Porosity Phi FS TOC Phi Components Phi e FS Clay TOC Phi e Clay FS
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TOC Calculation TOC Passey et al 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 Passey et al Responses in Organic β lean intervals TOC = Total Organic Carbon
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TOC Calculation TOC Schmoker
Note Mismatch TOC Schmoker Schmoker has three different correlations of RhoB with TOC: High Appalachian correlation Low Appalachian correlation Williston Basin Bakken
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Regular Density/Neutron Cross Plot
Calculations are: Total porosity Phit Shale volume VSH Effective porosity Phie Matrix volume Vma Fluid saturation in effective porosity β 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
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Shale Only Density/Neutron Cross Plot
Subtract the non-shale components are: Effective porosity β account for fluid content Matrix Volume Total Organic Carbon β as a volume fraction Determine porosity from the shale only density/neutron cross plot Calculate clay porosity as the product of cross plot porosity and π ππ» The plot can also be used to estimate clay mineral species
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Free Shale Porosity and Free Available Porosity
Free Shale Porosity = Total Porosity β Effective Porosity β 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 PhiFS Slight Mismatch
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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 β Published Relation Adsorbed G.I.P. (SCF) = X Area X Thickness X RhoB X (16 X TOC) Oil β Suggested Relation Adsorbed O.I.P. (Bbl) = S2 X X RhoB X h X Area X 7758 S2 = Hydrocarbons generated by thermal cracking
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Procedure 2 β Unconventional Reservoir Petrophysical Model
1 2 3 4 5 6 7 8 9 10 11 12 13 14 Raw Data Clean Formation Shale Formation 1 Gr, SP 4 Saturations 7 Porosity Comparison 10 Net Pay β Shale 13 2 Porosity 5 Bulk Volumes 8 Permeability 11 Shale Model 14 TOC Comparison 3 Resistivity 6 Lithology 9 Net Pay β Clean 12 Porosity Comparisons
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Procedure 3 β 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 βabnormally rapidβ 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
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Fracture Analysis Example
Note Fracture concentration in Niobrara C and Ft. Hays Individual Log Responses Stacked Data Pink O = Open Fractures β ? Low stress Blue C = Closed Fractures β ? High stress
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Procedure 4 β Relative Permeability Model
Reservoir π π° > π π°π’ π π° Buckles Relation Phie X S wi =Constant Holmes Adaptation Phie Q Γ S wi =Constant Slope = Q π π°π’ Reservoir at π π°π’ Solve the Corey relation S we = S w β S wi 1 β S wi K rw = S we Water K rh = 1β S we β S we Hydrocarbons
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Relative Permeability Example
Oil Well KEFF = π π« Γπππ«π¦ Reservoir Components Fluid Volume Relative Permeability Effective Permeability π π > π ππ’ Pay Flag Water/Oil Ratio
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Relative Permeability Example
Gas Well Low water adjacent to pay High water adjacent to pay Reservoir Components Fluid Volume Relative Permeability Effective Permeability π π > π ππ’ Pay Flag Water/Gas Ratio
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Procedure 5 β Rock Physics Model and Mechanical Properties β 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
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Rock Physics Model and Mechanical Properties
Raw Log DT DTS/DT DTS Density Neutron
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Youngβs Modulus vs. Poissonβs Ratio
Brittle Ductile
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Procedure 6 β Comprehensive Petrophysical Model
A Standard Template is Used for All Examples Clay Porosity 1. Fluid Saturation 4. Permeability 7. Water/Oil Ratio β Oil Reservoirs Water Bbl per MMCF β Gas Reservoir 10. Porosity Types β Phie and shale porosity 2. Bulk Volume β non shale fraction 5. Pay Flag β Clean Formation Yellow = Gross βSandβ Red = Net βSandβ Green = Pay 8. Brittle vs. Ductile 11. Porosity Types β Free Shale Porosity and TOC 3. Lithology 6. Pay Flag β Shale 9. Fractures
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Niobrara, Colorado β Oil
Clay Porosity Niobrara benches are brittle Very little shale contribution Niobrara shales are ductile Variable free shale porosity Fractures in Niobrara & Ft. Hays Fair to good core/log Correlation
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Bakken, Montana β Oil High free shale porosity Very high TOC
Clay Porosity High free shale porosity Very high TOC Water production from lower Three Forks
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Barnett, Texas β Shale Gas
Zone 1 β 4 Shale Higher free shale porosity than zone 5 Shales show variable ductile/brittle responses Good correlation core/logs
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Antrim, Michigan β Shale Gas
Pay contribution from most of the shales Shale shows variable brittle/ductile responses High TOC and free shale porosity Fractures sporadic Good correlation core/logs
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Western Canada β Shale Gas
Major contribution from shales Shales are entirely brittle High values of free shale porosity Good correlation core/logs
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Piceance Basin, Colorado β Tight Gas
Clay Porosity Minor shale contribution Fractures common Very low TOC and free shale porosity Sand intervals are brittle
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Bakken, North Dakota Oil-in-place in shale: 10.2 MMBO per 640 acres
Clay Porosity Oil-in-place in shale: 10.2 MMBO per 640 acres Carbonate: 9.6 MMBO High free shale porosity and TOC in both shale intervals
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New Albany, Illinois Clay Porosity Good correlation Core/Log
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References Michael Holmes, Antony Holmes, and Dominic Holmes βA Petrophysicial Model to Estimate Free Gas in Organic Shalesβ, Presented at the AAPG Annual Convention and Exhibition, Houston Texas, April, 2011. Michael Holmes, Antony Holmes, and Dominic Holmes βA Petrophysical Model for Shale Reservoirs to Distinguish Macro Porosity, Micro Porosity, and TOCβ, Presented at the 2012 AAPG ACE, Long Beach, California, April 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 OctoberΒ (2005). Michael Holmes, Antony Holmes, and Dominic Holmes βPetrophysical Rock Physics Modeling: A Comparison of the Krief And Gassmann Equations, and Applications to Verifying And Estimating Compressional And Shear Velocitiesβ presentation at the SPWLA 46th Annual Logging Symposium held in New Orleans, Louisiana, United States, June 26-29, 2005 James W. Schmoker βUse 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 Basinβ, 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 βA Practical Model for Organic Richness from Porosity and Resistivity Logsβ, AAPG 1990.
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