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The SPE Foundation through member donations
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The Society is grateful to those companies that allow their
professionals to serve as lecturers
Additional support provided by AIME
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
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Releasing Shale-Gas Potential
with Fractured Horizontal Wells
Erdal Ozkan
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
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3
US gas potential increased 4 to 6 times
from 1998 to 2008
(150 Tcf in 1998 and 500-1000 Tcf in 2008 – Arthur, 2008)
This is
due to the
economic
success
of the
shale
plays
Source – IAE, Lippman Consulting
Key Characteristics of Production
from Unconventional Reservoirs
Small pore sizes (nanoscale) 10-9 m ≤ dpore ≤ 10-6 m
Ultra tight formation 10-9 md ≤ k ≤ 10-3 md
Involvement of source rock
Natural fractures
Hydraulically fractured horizontal wells
…
…
5
Pore size distribution of Barnett
siliceous mudstone samples
Capillary pressure analysis
Most pore sizes are in
5 to 15 nanometers range
Mercury porosimeter analysis
80% of the pores have a pore
size less than 5 nanometers
Pore Sizes in Unconventional Reservoirs
Heterogeneous matrix pore-size distributions
Most matrix pore volume in nanopores
Pore network in shale sample (Ambrose et al., 2010)
Sample size: 4 m high, 5 m wide, and 2.5 m deep
3D Image Showing Surfaces
2D Image Showing Cross Section
2D cross-sectional image shows more kerogen and pore space than the surface
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Porosity and Permeability Ranges
Nano-pores
Micro-pores
Conventional oil and gas
dpore ≥ 1m
k ≥ 1mD
Tight gas
Shale gas
10-1 m ≥ dpore ≥ 10-2 m
1 D ≥ k ≥ 10-3 D
1m ≥ dpore ≥ 10-3 m
1mD ≥ k ≥ 1D
FLOW REGIMES IN POROUS MEDIA
Moderate Velocity, No-Slip Flow (Darcy’s Law)
Linear and Laminar Flow: Moderate p, v, & k
Micro-pores
Low Velocity, Slip Flow (Klinkenberg effect)
Non-Linear Flow: Low p, v, & k
Nano-pores
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Mixed Flow in Shale Matrix
Contribution of slip flow to apparent shale permeability
10
Ozkan et al. (2010 )
Fluid flow in Nano-Darcy Shale
“… numerical modeling requires gas permeabilities 2 to 4
orders of magnitude greater than observed to match flow
rates and ultimate recoveries … Some other, higher
permeability pathway through shale seems necessary.”
Cluff, Shanley, and Miller, AAPG 2007
Field Scale (m)
Core
Scale
(cm)
Micro Scale (mm)
FRACTURES IN SHALE
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THERMAL MATURATION AND MICROFRACTURES
Volume changes in kerogen and generated hydrocarbons during
thermal maturation cause microfractures
kerogen
(Meissner, 2007)
shale
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Hydraulic Fracturing Induces and
Rejuvenates Fractures in Shale
Microseismic Record of
Fracturing Events
Stimulated Reservoir Volume
(SRV) Representation
From Rimrock Energy, SPE 119896
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Microfractures in shale
(currently not characterized)
Shale-matrix model with microfractures (Apaydin et al., 2011)
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Pressure-Dependent Fracture Permeability
Experimental Data and Correlation (Cho, 2011)
k f  k fi e
 d f p f
Raghavan and Chin (2004)
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Pressure-Dependent Natural-Fracture Permeability
Haynesville Well History Matching (Cho, 2011)
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Pressure-Dependent Natural-Fracture Permeability
1200
ERROR IN PERMEABILITY
100 x (kfi-kf)/kf, %
PERMEABILITY, kf, md
2000
1000
1500
1000
800
kfi = 2000 md
pi = 5000 psi
df = 5E- 4 psi-1
600
400
500
200
0
1.E+01
1.E+02
1.E+03
PRESSURE, p, psi
0
1.E+04
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Dual-Mechanism, Dual-Porosity,
Dual-Fractured Reservoir Model
Hydraulically Fractured Horizontal Well
(Ozkan, Apaydin, and Raghavan, 2010)
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What’s the role of Hydraulic Fractures?
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Effect of Matrix Permeability
Productivity
increases with
increasing
matrix
permeability
for km ≤ 10-5
When flow
capacity of
natural
fractures is
reached, no
additional
productivity is
possible
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Effect of Natural Fracture Permeability
No difference in
productivity with
increasing
natural fracture
permeability
Natural fracture
permeability has
little effect on
productivity
Flow capacity of
the matrix is the
limiting factor
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Effect of Natural Fracture Density
Natural fracture
density has
significant effect
on flow capacity
of matrix.
Greater surface
area for flow
allows for a
greater volume of
fluid to be moved
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Effect of Hydraulic Fracture
Conductivity
Incremental
productivity
decreases as
conductivity
increases.
Volume of
fluid available
to flow is
limiting factor
Modeling Flow in Fractured Shale
Modeling Fractures as a Network of Natural Fractures
Physical System
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Missing something?
Where are the reservoir fractures?
Pressure and Derivative, psi
Pressure Buildup Test in Shale Reservoir (Field Data)
PRESSURE
DERIVATIVE
No characteristic
dual-porosity
behavior
(no derivative dip)
Time, hr
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Consequence of Using Conventional Tools
Transient dual-porosity model is more appropriate in shale
(What is in your reservoir simulator?)
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Conclusions
Our potential to recover gas from shale has been
increasing due to
●
●
new technologies to fracture horizontal wells
better understanding of flow and production
mechanisms
Marginal economics of shale-gas projects
requires more improvements in
●
●
characterization and modeling capabilities
analysis and prediction tools and techniques
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