1. 1
C.H. Sondergeld1, K.E. Newsham2, J.T. Comisky2, M.C. Rice2, and C.S. Rai1
1Mewbourne School of Petroleum and Geological Engineering
University of Oklahoma
2Apache Corp
Petrophysical Considerations in Evaluating
and
Producing Shale Gas Resources
SPE Unconventional Gas Conference, 23-25 Feb, Pittsburg Pennsylvania

2. 2
Increasing Scale
Particle
Motion
Storage
Capacity
Sorption Diffusion Darcy Pipe =SlippageBrownian
Nano-Porosity Interparticle-Porosity Wellbore =Fracture Porosity
Flow
Capacity
Electrochemical
Gradients
Random vibration
Viscous
Flow
Type
Pore
Type
1 micron
Hydraulic
Fracture
10 0.1 0.001Free molecular
flow
Continuum
Flow
Slippage
Flow
Transition
Flow
Knudsen
Flow
Regime
Exploitation of Gas Shales Involves Gas Flow at Many Scales
Ultimate supply is governed by flow at the smallest scales.

3. 3
Pore sizes from NMR and SEM imaging
Ion-milling- SEM backscattered image
Moncrieff, 2009
2
1 3S
T V r
  
0.05 m ms 
free
capillary
clay
bound
3 100r nm to nm
NMR and SEM agree!

4. 4
Parameter Desired Result
Dehydration Effects (Sw) < 40% Sw
Depth Shallowest Depth in Dry gas Window
Fracture Fabric and Type Vertical vs. horizontal orientation
Open vs. Filled with silica or calcite
Gas Composition low CO2, N, and H2S
Gas-Filled Porosity (Bulk volume gas) > 2% Gas Filled Porosity
Gas type (biogenic, thermogenic, or mixed) Thermogenic
Internal Vertical Heterogeneity Less is better
Mineralogy > 40% Quartz or Carbonates
< 30% Clays
Low expandablilty
Biogenic vs. detrital silica
OGIP (free and sorbed) > 100 BCF/section
Permeability > 100 nanoDacry
Poisson's Ratio (static) < 0.25
Pressure > 0.5 psi /ft
Reservoir Temperature > 230 F
Seals Fracture Barriers Present Top and Base
Shows High gas Readings-Production
Stress < 2000 psia Net Lateral Stress
Thermal Maturity Dry gas window > 1.4 Ro
Thickness > 30 m
Total Organic Content (and Type) > 2%
Wettability Oil prone wetting of kerogen
Young's Modulus > 3.0 MMPSIA
Desirable Gas Shale Characteristics

5. 5
Compositional Variation in Shales (limey system)
Transmission
FTIR
16 minerals

6. 6
Compositional Variations in Shales
FTIR predict more clay and less quartz! Better agreement with logs and
point counting.
Weight%

7. 7
TOC from Logs: Modified Passey Method
• Passey method under predicts
TOC in mature and over-mature
gas shale
• Use Multiplier ‘C’
• This example …
Vro = 2.2, LOM = 14.5, max ∆logR = 1.0
Predicted TOC =
∆ logR x 10(2.297 – 0.1688 x LOM) x C
TOC∆ logRLOM
Un-Modified Passey Passey with C = 4

8. 8
Brittleness from Composition and Velocities
Vp&Vs  EMatched Mineralogy
Brittleness Index
= (Qtz / (Qtz + Carb + Clay)
BRITTLENESS INDEX
= (Ebrit + brit)/2
Ebrit = ((E-1)/(8-1))*100
brit= ((-0.15)/(0.4-0.15))*100
(Rickman et al. 2008)
Brittleness from
composition similar to
that from sonic logs

9. 9
Intrinsic properties should not depend
on sample size.
1.00E-06
1.00E-05
1.00E-04
1.00E-03
1.00E-02
1.00E-01
0.1 1 10 100
K,md
particle size, mm
sh-12 sh-05
Shale
Cui et al. 2009Luffel et al. 1993
nd
d

10. TGA_FTIR Data for Shales
• Equilibration time is
composition dependent but
<300 minutes
• Only water detected
100 oC27 oC
100 oC
100 oC
42 oC
72 oC
100 oC 1 hr
3 hr
6 hr
9 hr
H2O
Removes residual hydrocarbons
and water but retains TOC,
matrix, and clay bound water.
Useful in determining heat
treatment before porosity and
permeability measurements.

11. 11
Porosity Comparison
2435.00
2440.00
2445.00
2450.00
2455.00
2460.00
2465.00
2470.00
2475.00
2480.00
0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0
Depth,m
As Received Core Porosity,%
Lab 1 Lab 2 Lab 3
2435.00
2440.00
2445.00
2450.00
2455.00
2460.00
2465.00
2470.00
2475.00
2480.00
0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0
Depth,m
Dry Core Porosity,% BV
Lab 1 Lab 2
“As Received” Comparison Dry Comparison
Wide variation in simple properties among labs, greater than a factor of 2 on
as received samples. Real or procedural?

12. 12
Grain Volumes measured by two labs
2.00
2.20
2.40
2.60
2.80
3.00
2.00 2.20 2.40 2.60 2.80 3.00
Lab2ARBulkDensity,gcc
Lab 1 AR Bulk Density, gcc
2.40
2.50
2.60
2.70
2.80
2.90
2.40 2.50 2.60 2.70 2.80 2.90
Lab2ARGrainDensity,gcc
Lab 1 AR Grain Density, gcc
“As Received” Bulk Density “As Received” Grain Density
Bulk volume measurement is consistent, whereas grain
volume measurement is different. This produces differences
in reported porosities.

13. 13
1.00E-06
1.00E-05
1.00E-04
1.00E-03
1.00E-02
1.00E-01
0.1 1 10 100
K,md
particle size, mm
sh-12 sh-05
1.0E-12
1.0E-09
1.0E-06
1.0E-03
1.0E+00
0 5 10
Porosity, %
k,md
crushed
barnett
crushed2
BC-CA
marcellus
Y_gs
syn
Gas Shale Permeability
After Cui et al. 2009
Strong particle size dependence
After Wang and Reed, 2009
Wide range in measured perms
reflecting techniques and sampling ?
nd
d
pd
d
nd

14. 14
Composite of TRA permeabilities and porosities
for a number of gas shales.
Very limited dynamic range. Shales from Canada, Illinois, Texas and Arkansas
0.001
0.01
0.1
1
10
0 5 10 15
k,md
Porosity, %
TRA-GasShale
hr1
b1
b2
b3
b4
sws
swgh
swgm
ofr
rl1
d

15. 15
Pressure dependence of shale permeability:
0.0001
0.0010
0.0100
0.1000
1.0000
10.0000
100.0000
0 10 20 30 40 50 60
k,md
Pconf, MPa
A B C Y1 y2 y3 y4 y5 wel pier
Kd
nd

16. 16
Pressure dependence suggest microcrack influence
Walsh’s theory (1981) predicts linear dependence in this variable space. Single
smooth plane in Al2O3 is the upper bounding red line. All other plug
measurements including “whole” plugs and fractured shales fall below this.
1
3
2
1 ln
o o o
k h P
k a P
    
       
    
fractured
surfaces

17. 17
0
10
20
30
40
50
60
70
80
90
0 10 20 30 40
Young'sModulus,E,GPa
Pressure, MPa
v
h
45
Zun
Pathi
Enz
h1
h2
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5
0 10 20 30 40
n
Pressure, MPa
v
h
45
Zun
Pathi
Enz
h1
h2
Elastic Properties (Young’s modulus, Poisson’s ratio)
Wide range in mechanical properties driven by anisotropy and composition.
Horiz
45o
Horiz
45o

18. 18
Anisotropy
 p-wave anisotropy
Both approach 30-50% in gas shales!
2 2
2
2


p _h p _v
p _v
v v
v

2 2
2
2


s _h s _v
s _v
v v
v

Consistent with mechanical properties, Young’s modulus anisotropy!
Symmetry TI to Orthorhombic
0
0.1
0.2
0.3
0.4
0.5
0 0.1 0.2 0.3 0.4 0.5


Barnett
Floyd
1:1


 s wave anisotropy
horizontal
45o
vertical

19. 19
0
1
2
3
4
5
0.5 1 1.5 2 2.5 3
Eh/Ev
nxy/nzx
Floyd
Barnett
Baxter
Effect of Anisotropy on Closure Stress
xy =0.25, zx= 0.375 and Eh = 2Ev produces a h = v
Frac containment becomes difficult!
1
H zx
h v
v xy
E
E

 

 
    
Austin Slate
0
100
200
300
400
500
600
700
0 20 40 60 80 100
Angle
FailureStrength,MPa.
40k
30k
20k
10k
5k

20. 20
2435.0
2440.0
2445.0
2450.0
2455.0
2460.0
2465.0
2470.0
2475.0
2480.0
0.0 20.0 40.0 60.0 80.0 100.0
Depth,m
AR Water Saturation
Lab 1 Lab 2 Lab 1 Sw Corrected to Lab 2 Porosity
Saturation changes with heating and time
Saturation estimates are
affected by accuracy of
porosity measurements
Mavor, 2009

21. 21
Mineralogy varies considerably in a particular shale
TOC estimation by Passey et al. (1990) method works well with a multiplier
Logs require independent mineralogy calibration , FTIR fast and sufficient
Core handling and preparation needs to be standardized
Permeability on crushed samples reflect grain size more than matrix perms
Permeability measurements on cores display a strong crack component
Variable salinities render Archie saturation calculations questionable
Anisotropy is strong (30-50%) and influences closure stress estimates
and fracture containment
Recommend a committee to create standards and protocols for shale measurements
revisit the GRI recommendations, we can’t afford to crush ¾ lb of shale!
Conclusions and Recommendations