Horizontal Fracturing in Shale Plays
Matt McKeon
Shortening the learning curve
•
•
•
Historically:
y a trial-and-error p
process
Data acquisition
USA analog fields can speed up
evaluation and development
Quantify
Construct
Complete
Analyze
Gas Rate Sim
Gas Rate
Oil Rate
Oil rate Sim
2
Recent plays: fracture stimulations are evolving
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WaterFracs
8-10 Stages
80 100 BPM
80-100
1.5 MM lbs prop
100 Mesh, 40/70
1 ppg Max
7 MM Gal
40,000 HHP
350-450’/Stage
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2008
2009
Hybrid/Conv
12-15 Stages
40-60 BPM
3-4 MM lbs prop
(total)
30/60 20/40
30/60,
3-4 ppg
4 MM Gal
25,000 HHP
250-300’/Stage
2010
Eagle Ford
3
Even Barnett stimulation is still changing
Barnett Shale Completion Roadmap
Barnett Shale Completion Roadmap
90
700
35000
600
30000
4500
80
4000
70
3500
500
25000
400
50
40
300
b b l/s ta g e
3000
20000
2500
2000
15000
30
1500
10000
sks/stag
ge
200
20
s p a n ft.
A vg. B PM
60
10
BPM
Treatment span
0
100
0
1999
2000
2001
2002
2003
2004
year
2005
2006
2007
2008
5000
bbl/stage
sks/stage
0
1000
500
0
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
Year
4
Shale Gas Development Process Workflow
Data Acquisition
q
5
5
Shale parameters to enhance commercial production

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Gas content
Thermal maturity (Ro)
Permeability
Porosity
Pressure
TOC
Water saturation
Well bounded & thick zone
Moderate clay content
Well bounded
Brittle shale (fracability)
Natural fractures
: > 100 scf/ton
: 0.7 to 2.5+ range; 1.2 typical
: greater than 100 nanodarcies
: > 4%
: above normal
: > 2%
: < 45%
: > 100 ft
: < 40%
: i.e. good frac barriers
: i.e. low Poisson’s & high YM
: moderate presence
6
Shale
Prospect
Woodford
Barnett
Haynesville
Marcellus
Eagleford
Bakken
5.5
1-8%
~1.5 – 6 (Avg. ~3.8)
8 - 15%
3 – 8%
3- 15%
2 - 12 %
4,100 – 4,300
6,000 – 14,000
5,400 – 9,500
10,500 – 14,000
4,500 - 8,500
5,000 - 13,000
8,000 - 11,000
53
100 - 220
100 - 500
60 - 350
50 - 300
40-500
6-15ft & 80-145 ft
BHT (° F)
160
150-225
150
280-380º F
100-150
150 - 350
190 - 240
TOC (%)
3.95
3-9%
4-8%
2-5%
3-10%
0.5-9%
Upper-11%-40%
Lower=8%-21%
Press Grad (psi/ft)
0.48
.45-.68
0.52
0.85 - 0.93
0.4 - 0.7
0.4 – 0.85
0.5 - 0.6
Frac Grad (psi/ft)
0.7
.7-.9
~0.6 – 0.75
>0.90
0.9 – 1.2
.88-1.1
0.70 – 0.85
Avg Perm (μd)
0.1
0.05-0.4
0.05 – 0.4
<0.005
0.2 - 2
400-1200
20 - 500
Sw (%)
27
33%
<35 no free water
<25
10-30
25 - 60
Lithology (%)
Silica rich
Silica- Chert 30-60%
Silica rich 35-50 v/v
Shale is soft (ductile)
Calcite rich-in areas
silica rich (in areas)
organic rich
High clay mineral
fraction
Variable formation
properties
Illite clay-dominated
Quartz/Plagioclase/
F ld
Feldspar
Carbonates
Siderite/Pyrite
~3-5% carbon
content
High Illite-dominate
clays
L k lik
Looks
like ““poker
k
chips”
High in Calcites
Silty, sandy, dolomite
grading to laminated
shaly interval. Some
natural fractures.
Below is Sanish
YM (x106 psi)
3.48
4-8
6-10
2-3
2-5
1-4
Upper/Lower= 2 - 4
Middle=4-6
PR (%)
0.206
0.15-0.25
0.13-0.25
0.23 – 0.27
0.19 – 0.23
0.20-0.27
Upper/Lower=-0.250.28
Middle= 0.2 – 0.25
Quartz, wt %
54
25-54
40-60
25-52
10 - 40
1—30
15 - 70
Plagioclase
feldspar, wt
%
10
7-13
2-5
8-17
0 – 10
0-17
1-3
C l it wtt %
Calcite,
37
3.7
7 20
7-20
5 30
5-30
13 44
13-44
5 – 20
25 95
25-95
15 - 65
2-8
1-5
-
<2
0-23
2-6
17-46
5-25
12-20
25 - 60
1-50
1 - 13
Porosity (%)
TVD (ft)
Thickness (ft)
Smectite,wt %
Illite, wt %
11.9
Kaolinite wt %
8
0
0
-
<2
0-14
0-2
Chlorite, wt %
11.9
1
0
4-7
0 – 10
0-7
1-3
Ro (M
R
(Maturity
t it off
Shale)
1 23
1.23
0 75 – 1.45
0.75
1 45
0616
0.6-1.6
1 – 1.2
12
0 8 – 3.0+
0.8
30
0 75 – 2.16
0.75
2 16
0 45 – 0.60
0.45
0 60
Analog Analysis
U.S. shale play: choose stimulation
Barnett
Woodford
Waterfrac (WF)
WF /Linear Gel
WF, Hybrid, &
X-Linked
Hybrid
WF and Hybrid
5,400-9,500 ft.
6,000-14,000 ft.
10,500-14,000
5,000-13,000 ft.
4,500-8,500 ft.
4,000 ft.
4,000 ft.
4,500 ft.
4,000 ft.
3,000-5,000 ft.
48
4-8
6 12
6-12
10 - 15
12 15
12-15
10 14
10-14
Fluid Volume
5.0 MM (8 stg)
6.5 MM (10 stg)
5.0 MM (10 stg)
4.0 MM (12 stg)
5.0 MM (12 stg)
Proppant Vol.
3.5 MM lbs.
4.5 MM lbs
2.5 MM lbs
3.5 MM lbs
5.5 MM lbs
Cemented Csg.
Cemented Csg.
Cemented Csg.
Cemented Csg.
Cemented Csg.
(1)P&P
(2)BASS
(3)Hydrajet
(1) P&P
(2) BASS
(3) Hydrajet
(1) P&P
(2) BASS
(3) Hydrajet
(1) P&P
(2) BASS
(3) Hydrajet
(1) P&P
(2) BASS
(3) Hydrajet
Span/Stage
400 ft.
400 ft.
300 ft.
250-400 ft.
150-400 ft.
Clusters/Length
4
2 4 ft.
2-4
ft
4
2 4 ft
2-4
ft.
4-6
1 2 ft
1-2
ft.
4-8
1 2 ft
1-2
ft.
3-5
2 4 ft
2-4
ft.
Frac System
TVD
Lateral Length
Stages
Completion
Type
Haynesville Eagle Ford
Analog Analysis
Marcellus
Shale Analysis Log
 Where would you perforate?
 What is the TOC and gas content?
Mineralology
Lithology
Brittle
or
Ductile?
Kerogen
Content
 Will it frac and what is the relative
fracture
width and barriers?
Reservoir
Properties
Natural
 What is the
shale
Fractures?
in place?
Unconfined
Compressive
volumetric
gas
Strength
 What is the shale porosity and
permeability?
 Where is the organic rich shale?
 Where are the zones of highest
kerogen content
Shale
Type
Frac
“Ease”
TOC
Hydrocarbon
Content
SPE 115258
9
Shale fracturing simulation
• Designed
g
for complex
p
fracturing
• Couple available data
with microseismic to
optimize fluid system
and
d frac
f
d i
design
• Recalibrate model based
on post job analyses and
regional variations
OBJECTIVE
Maximize stimulated reservoir volume (SRV)
(
)
11
Shale fracture characteristics
To create complexity you must have:
1. Pre-existing natural fissures
2. Low differential horizontal stresses ((net p
pressure > σm)
3. Brittleness
Ductile Brittle
• Tight Gas Sands
• Haynesville
• Eagleford
• Woodford
a e
• Bakken
• Marcellus
• Barnett
12
Shale Completion Strategy: Based on Formation Brittleness & Liquid Production
Brittleness
Fluid System
70%
Slick Water
60%
Slick Water
50%
Hybrid
y
40%
Hybrid
30%
X-Linked
20%
X-Linked
X
Linked
10%
X-Linked
Fracture
Geometry
SPE 115258
Fracture Width
Closure Profile
Brittleness
Proppant
Concentration
Fluid
Volume
Proppant
Volume
Liquid
Production
70%
Low
High
Low
Low
High
Low
High
High
60%
50%
40%
30%
20%
10%
13
Shale fluid decisions
Shale Type Frac Type
Fluid Type &
Prop ppg
Brittle &
low clay
•Water 0-2% KCL
•0.1-2 ppg
•Complex network
•No embedment
Brittle & high •Complex network
clay
•Some embedment
•Water 2-7% KCL
•Linear gel.
•0.1- 3 ppg
Ductile & low •Less complex
clay
•Moderate embedment
•Water 0-2% KCL
•Linear gel. X-Link Tail
•0 5 – 5 ppg
•0.5
Ductile &
high clay
•Linear Gel 2-7% KCL
•X-Link
•0.5-10 ppg
•Bi-Wing
•High
High embedment
14
14
Lateral design, stage intervals & well spacing
• Lateral
• Drilled in direction on minimum horizontal stress for transverse fracturing
• Greater than 90 degree deviation is common practice
• Stay in best portion of the reservoir while drilling
• Longer laterals yield more production – to a point → cost considerations
• Stage
g
intervals
• Number of intervals varies by shale play – most 300 to 400 ft
• Most often, shorter intervals increase SRV and production → more cost
• Couple with perforation interval distribution for optimum SRV from frac
• Well
Spacing
15
Perforation clusters
• Typically evenly spaced along stage interval – good rock or bad
• Number of clusters varies by shale play, less perm & complexity → closer
• Number of perfs affect limited entry diversion
placed the less contribute to production
• The more clusters placed,
• Placement in better rock (fracs, brittle) may enhance SRV and production
16
Shale Fracture Characteristics
Definition of Brittleness from Rock Mechanics
SPE 115258
Haynesville
Marcellus
Eagle
g Ford
Woodford
ood o d
Barnett
70.00
56.00
42.00
28.00
BRIT
14.00
00.00
Barnett – example pump schedule
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
4000 ft laterals
Span = ± 400 ft
Stage size = 15,500 bbl/stage
Prop volume = 4300 sks/stage
Number of stages 6 → 8
P
Prop
type:
t
60% 100 mesh,
h
40% 40/70
Rate = 70 BPM
End sand conc = 1.25
1 25 – 1.5
1 5 ppg
Treating pressure = 4000 psi
SRV (ft3)= 4/3*π*ABC
A=network
A network width
B=frac length
C=height/2
pad
slurry
slurry
slurry
slurryy
slurry
slurry
slurry
flush
% 100 mesh
% 40/70
% pad
avg ppg
lbs 100 mesh
lbs 40/70
total volume
gal
100000
40000
40000
100000
100000
100000
100000
70000
12000
ppg
prop
lbs
0.3
0.5
0.6
0.7
0.8
1
1.25
100 mesh
100 mesh
100 mesh
100 mesh
100 mesh
40/70
40/70
12000
20000
60000
70000
80000
100000
87500
56.34%
43.66%
15.38%
0.66 ppg
total lbs
total time hr
242000 lbs
187500 lbs
650000 gal
rate
80
80
80
80
80
80
80
80
80
429500 lbs
3.38 hr
15,476 BBL
time
29.76
12.07
12.18
30.58
30.71
30.85
31.12
22.02
3.57
Formation hardness and proppant embedment
90
80
70
60
BHN #
B
50
40
30
20
10
0
Woodford
Marcellus
Floyd
Eagle Ford Haynesville
Bossier
Barnett
CV Lime
Ohio SS
Coal
19
Haynesville - example pump schedule
6 perforation cluster - 72 BPM
Stage
Fluid
Volume
Prop
Prop Concent Rate/cluster
1 Treated Water
36000 --
2 Guar (R11)
15000 100 mesh
0.5
12
7500 lb
3 Guar (R11)
20000 100 mesh
0.75
12
15000 lb
4 Guar (R11)
25000 100 mesh
1
12
25000 lb
5 HYBOR G (R27)
20000 --
6 HYBOR G (R27)
45000 Main Proppant
0.5
12
22500 lb
7 HYBOR G (R27)
45000 Main Proppant
1
12
45000 lb
8 HYBOR G ((R27))
45000 Main Proppant
pp
2
12
90000 lb
9 HYBOR G (R27)
36000 Main Proppant
3
12
108000 lb
10 HYBOR G (R27)
22500 Main Proppant
4
12
90000 lb
11 Guar (R11)
Total fluid volume per stage
12
12
flush
12
309500 gal
Total proppant per stage
47500 lb 100 mesh
355500 lb Main Proppant
Pump Time per Stage
102 minutes
Main Proppant =
12 Stages per Well
Volume / Well =
100 mesh / Well =
Main Proppant / Well =
3,714,000 gal
570,000 lb
40/70 PowerProp or
40/80 HydroProp or
% pad =
37%
30/60 CarboProp or
4,266,000 lb
30/50 InterProp or
20/40 InterPorp
Estimated Pipe Friction =
Estimated Perf Friction =
BHTP =
Ph =
Surface Treating Pressure =
3300 psi
1200 psi
11500 p
psi
5000 psi
11000 psi
6p
perf clusters
Volume / Cluster =
100 mesh / Cluster =
Main Proppant / Cluster =
51,583 gal
7,917 lb
59,250 lb
20
Simultaneous fracturing results
• Simulfrac or
pp
Zipperfrac
– Typically more
microseismic
activity
– Overlapping
microseismic
behavior
– Still see general
fracturing behavior
SPE 119896 (Rimrock)
Barnett - refrac potential
Barnett Shale: Refrac – Water Frac
Barnett Shale: Gel Frac
1600
SRV vs. 6-month Average
Gel
Frac
1200
3500
Water Frac
3000
6-Month Average (MCFD)
Gas Flow Ra
ate (Mcf/d)
1400
SPE 115771
1000
800
600
400
2500
2000
1500
y = 20.284x + 319.3
R2 = 0.5571
1000
500
200
0
0
0
180
360
540
720
900
Time (days)
1080
1260
1440
0
20
40
60
80
100
120
140
6
SRV (10 m3)
22
Marcellus - more height growth & planar vs. Barnett
•
Experiment
– Lite frac
•
•
•
•
•
•
•
3000 ft lateral
6 stages
550,000 gal/stg
97 bpm rate
100,000 lb/stg
Slickwater
Barnett
Typical
– More planar than
Barnett
– Complexity
• More stages
• More perf clusters
SPE 131783 Range Resources Corp
Haynesville - significant height growth
• Haynesville
– GMX fracture treatment
– 3,000
3 000 – 5,000
5 000 ft laterals
– 7 – 10 stages
• 300 ft spacing
• 2 perf clusters/stage
– Stimulation
•
•
•
•
300 to 500 K gal/stage
65 bpm rate
270,000 lb proppant/stage
Slickwater, hybrid, & X-link
SPE 12507 GMX Resources
Woodford - containment
Fracture Lengths
•Stage 1: 2500’
•Stage 2: 3300’
•Stage 2 RF: 1400’
•Stage 4: 1200’
Fracture Heights
•Stage 1: 250’
•Stage 2: 280’
•Stage 2 RF: 280’
•Stage 4: 280’
•Well
Well contained
SPE 110029
Antero
CarrWell
Obs
Well
Estate
#1
Obs
#113-1H
Pettigrew 19-1H
Obs Well #2
Treatment
Well 18-1H
Pettigrew
Woodford
FM
Stage 1 events
Stage 2 events
Stage 2RF events
St
Stage
3 events
t
Looking NW
Utica
Woodford
Barnett
Haynesville
Marcellus
Eagleford
Bakken
1-8%
~1.5 – 6 (Avg. ~3.8)
8 - 15%
3 – 8%
3- 15%
2 - 12 %
6,000 – 14,000
5,400 – 9,500
10,500 – 14,000
4,500 - 8,500
5,000 - 13,000
8,000 - 11,000
Thickness (ft)
100 - 220
100 - 500
60 - 350
50 - 300
40-500
6-15ft & 80-145 ft
BHT (° F)
150-225
150
280-380º F
100-150
150 - 350
190 - 240
TOC (%)
3-9%
4-8%
2-5%
3-10%
0.5-9%
Upper-11%-40%
Lower=8%-21%
.45-.68
0.52
0.85 - 0.93
0.4 - 0.7
0.4 – 0.85
0.5 - 0.6
.7-.9
~0.6 – 0.75
>0.90
0.9 – 1.2
.88-1.1
0.70 – 0.85
0.05-0.4
0.05 – 0.4
<0.005
0.5 - 2
400-1200
20 - 500
33%
<35 no free water
<25
10-30
25 - 60
Silica- Chert 30-60%
Silica rich 35-50 v/v
Shale is soft (ductile)
Calcite rich-in areas
silica rich (in areas)
organic rich
High clay mineral
fraction
Variable formation
properties
Illite clay-dominated
Quartz/Plagioclase/
F ld
Feldspar
Carbonates
Siderite/Pyrite
~3-5% carbon
content
High Illite-dominate
clays
L k lik
Looks
like ““poker
k
chips”
High in Calcites
Silty, sandy, dolomite
grading to laminated
shaly interval. Some
natural fractures.
Below is Sanish
4-8
6-10
2-3
2-5
1-4
Upper/Lower= 2 - 4
Middle=4-6
0.15-0.25
0.13-0.25
0.23 – 0.27
0.19 – 0.23
0.20-0.27
Upper/Lower=-0.250.28
Middle= 0.2 – 0.25
Quartz, wt %
25-54
40-60
25-52
10 - 40
1—30
15 - 70
Plagioclase
feldspar, wt
%
7-13
2-5
8-17
0 – 10
0-17
1-3
C l it wtt %
Calcite,
7 20
7-20
5 30
5-30
13 44
13-44
5 – 20
25 95
25-95
15 - 65
Smectite,wt %
2-8
1-5
-
<2
0-23
2-6
17-46
5-25
12-20
25 - 60
1-50
1 - 13
Kaolinite wt %
0
0
-
<2
0-14
0-2
Chlorite, wt %
1
0
4-7
0 – 10
0-7
1-3
0 75 – 1.45
0.75
1 45
0616
0.6-1.6
1 – 1.2
12
0 8 – 3.0+
0.8
30
0 75 – 2.16
0.75
2 16
0 45 – 0.60
0.45
0 60
Porosity (%)
TVD (ft)
Press Grad (psi/ft)
Frac Grad (psi/ft)
Avg Perm (μd)
Sw (%)
Lithology (%)
YM (x106 psi)
PR (%)
Illite, wt %
Ro (M
R
(Maturity
t it off
Shale)
?
Marcellus shale – frac height vs aquifer depth
Thank You