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Transcript of Overview of Shale Plays - edg1.vcall.comedg1.vcall.com/slides/164758/slides.pdf · Overview of...
EnerCom's London Oil & Gas Conference
16 June 2011
London, England
Overview of Shale Plays
Danny D. Simmons
Barnett Shale
Historical Gas Production
Gas
Production
Rig
Count
0.0
1.0
2.0
3.0
4.0
5.0
6.0
Jan 00 Jan 01 Jan 02 Jan 03 Jan 04 Jan 05 Jan 06 Jan 07 Jan 08 Jan 09 Jan 10 Jan 11
Daily G
as P
rodu
cti
on
(B
CF
D)
0
50
100
150
200
250
300
Rig
Cou
nt
Barnett Shale
Chronology of Completion Techniques
Older vertical well
with older gel-based
fracture stimulation
Recent horizontal well with
newer light-sand based
fracture stimulation
Cum 1,362 MMCF
Newer vertical well with
newer light-sand based
fracture stimulation
Cum 857 MMCF
Refrac treatment of older vertical
well with newer light-sand based
fracture stimulation
Cum 692 MMCF
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Jan-95 Jan-96 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05
Ga
s R
ate
(M
MC
FD
)
Barnett Shale Type Curve
Northeast Wise County
100
1,000
10,000
100,000
0 12 24 36 48 60 72 84 96 108 120
Time (Months)
Gro
ss G
as (
MC
F/M
on
th)
0
20
40
60
80
100
120
Well C
ou
nt
Barnett Shale
Variation in Well Performance
• Wide range of performance trends for
wells in close proximity
• EURs range from 0.3 Bcf to 3.6 Bcf
– Average EUR is 1.5 Bcf
• There may not be a 'typical' well
Barnett Shale
Northeast Wise County
Barnett Shale
Northeast Wise County
100
1,000
10,000
100,000
0 12 24 36 48 60 72 84 96 108 120
Time (Months)
Gro
ss G
as (
MC
F/M
on
th)
0
20
40
60
80
100
120
We
ll Co
un
t
Average of 107 wells
Projection of Average Production
Well Count
Year P25 Mean P50 P75 Avg. Lateral Length (Feet)
2002 and Earlier 1,814 1,533 1,363 743 1,297
2003 2,729 1,999 1,553 847 1,414
2004 2,775 2,172 1,812 1,005 1,885
2005 3,074 2,238 1,853 1,054 2,391
2006 3,011 2,217 1,968 1,004 2,921
2007 3,591 2,704 2,452 1,462 2,930
Gas EUR (MMCF)
Barnett Shale
Variation in Well PerformanceYearly Gas Ultimate Distribution
Barnett Shale Tier 1 Area
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
0 10 20 30 40 50 60 70 80 90 100
Greater Than (Percent)
Ga
s E
sti
ma
ted
Ult
ima
te R
ec
ov
ery
(M
MC
F)
2002 and Earlier 2003 2004 2005 2006 2007
`
Completion Improvements
Lateral Length
No. of Fracs
Type of Proppant
Shale Gas
Comparison between Plays
Play
Age
Depth
(feet)
Thickness
(Net feet)
Pressure
(psi)
TOC
(%)
Porosity
Net (%)
BCFE/D
(Jan 2011)
Barnett
Mississippian
6,500-8,500 100-300 3,500-
6,000
2.0-5.0 3-5 5.3
Fayetteville
Mississippian
4,000-7,000 100-200 2,000-
4,500
2.0-5.0 3-5 2.5
Haynesville
Jurassic
10,500-
13,500
100-200 8,500-
12,000
0.5-3.0 5-9 5.0
Marcellus
Devonian
4,000-8,500 50-200 2,000-
6,000
3.0-7.0 3-10 2.3
Eagle Ford
Cretaceous
6,000-13,000 100-200 5,500-
10,500
2.0-7.0 3-9 2.2
Time
Rate
50 mbo
400 mbo
200 mbo
• How much oil and/or gas are wells going to make, and
• Can my Company make $ drilling wells?
Simplistic Goals of Reservoir Engineer
OOIP
OGIP
Temperature
TOC
Porosity vs. TOC
Porosity
Pressure
Fluid Analysis
Free Gas vs.
Adsorbed Gas
Natural
Fracture
Hydraulic
FractureRo
Permeability -
Natural
Permeability -
Induced
Well SpacingRecovery Factor
Vertical vs. LateralRecovery per Incr.
Lateral Foot
Prices
Costs
GR GRRT D,N
10’High Quality Net
60’ Quality Net
General Principles
Higher silt content
(Rt and Rhob)
Higher organic
content
(GR)
Hydrocarbon
ProfileHigher silt content
(Rt and
Rhob)
430' Gross
250' Net < 2.5 g/cc
OGIP
+/- 175 BCF/Sq Mi
More is Better…
Storage Capacity (In-Place)
Flow Capacity (Perm)
Reservoir Energy (Rec. Factor)
Shale Gas Storage SystemS
ch
lum
berg
er P
rivate
SPE Mid-Continent Section – May 15, 2003
Gas Storage & Production Mechanisms
Naturally Fractured, Organic-Bearing Shale Reservoirs
Desorption From
Internal Surfaces
Flow Through
the Matrix
Flow in the Natural
Fracture Network
Organic
CarbonMatrix
Natural
Fractures
Hydraulic
Fracture
Density & SpacingPorosity
Permeability
Net Thickness
Reservoir Pressure
TOC - Total Organic
Carbon
120 - 140 Bcf/mi2
Adsorbed Gas
associated with TOC
Sch
lum
berg
er P
rivate
SPE Mid-Continent Section – May 15, 2003
Gas Storage & Production Mechanisms
Naturally Fractured, Organic-Bearing Shale Reservoirs
Desorption From
Internal Surfaces
Flow Through
the Matrix
Flow in the Natural
Fracture Network
Organic
CarbonMatrix
Natural
Fractures
Hydraulic
Fracture
Density & SpacingPorosity
Permeability
Net Thickness
Reservoir Pressure
TOC - Total Organic
Carbon
120 - 140 Bcf/mi2
Standard porosity associated with space
between grains or shale particlesSubmicroscopic porosity associated with
conversion of TOC to hydrocarbons
Nanopores
TOC
Reed et al., Texas BEG; Presented by Bob Loucks, AAPG
San Antonio 2008; Submitted for publication 2008
Free Gas
associated with matrix porosity
TOC @ 3% by weight equates to 6% volume
(reading on the standard porosity log)
Organic Material-Porosity Relationship
Log Porosity (Volume %) = TOC (wt%) + Real Porosity (Volume %)
This is the single most significant difference between Shale Free
gas analysis and conventional reservoir Free Gas analysis
TOC
Nanopores
Natural Fracture Density
Increased density
• increases porosity,
• increases cross-sectional area,
• decreases distance fluid has to flow
Gas Reservoir Permeability vs Recovery Factor
0.0000001
0.0000010
0.0000100
0.0001000
0.0010000
0.0100000
0.1000000
1.0000000
10.0000000
100.0000000
1,000.0000000
10,000.0000000
0% 5% 10% 15% 20% 25% 30% 35%
Porosity
Re
serv
oir
Pe
rme
ab
ilit
y (
md
)
Unconventional
Tight
Recovery Factors
30 to 50%
Conventional
Recovery Factors
50 to 95%
Shale
Recovery Factors
5 to 30%
Gas Reservoir Permeability vs. Recovery Factor
Maximizing Drainage Area
dx
dy
Contributing Volumes Less than 100% Gross Rock Volume
Increasing Frac
Stages
Increasing Frac
Density
Downspacing
Horizontal Drilling Schematic
Shale Gas
Evaluation Considerations
• Shale plays may require considerable initial capital expenditures to allow commercial access and determine economic feasibility.
• Geoscience costs tend to be very large early in shale plays:
Seismic in areas without recent petroleum exploration activity
Coring and laboratory analysis
• Learning curve – earliest wells in new play may deliver poor results as drilling and completion technology is perfected.
• General shale play economics improve over time due to: More effective drilling and completion techniques
Better understanding of reservoir and identification of "sweet spots"
• Long-term investment Shale gas plays have very large in-place volumes and very large drilling
location inventories that may take decades to realize.
• Two-day seminar (no registration cost)
• Dallas – May 2012
• London – June 2012
• Dates and locations will be announced in early 2012
• Pre-register on-line at www.netherlandsewell.com
Netherland, Sewell & Associates, Inc.
Because there is a difference.
www.netherlandsewell.com
DallasThanksgiving Tower
1601 Elm Street
Suite 4500
Dallas, Texas 75201
214-969-5401
Houston 4 Houston Center
1221 Lamar
Suite 1200
Houston, Texas 77010
713-654-4950