HiWAY: The Quest For Infinite Conductivity
Innovation for a step-change in Hydraulic Fracturing
Presentation prepared for
Jornada De Maxi-Fracturas
May 2012
HiWAY: A Paradigm Shift in Hydraulic Fracturing
1950
1960
1970
1947 First hydraulic fracturing job
1950 Fracturing using gelled oil
1960 Water-based, non crosslinked fluids
1968 Borate crosslinked fluids
1973 Crosslinked derivatized guars (HPG, CMHPG, etc)
1980
1977 High-strength ceramic proppants
1980 Foamed fracturing
1990
1988 Encapsulated breakers
1990 Fiber based flowback control
1994 Low polymer loadings
1997 Viscoelastic surfactants (VES)
2000
2001 Micro-seismic used to monitor frac jobs
2003 Horizontal well, multistage fractures
2005 Fiber based proppant transport
2010
2010 HiWAY* Flow-Channel Fracturing
2011 Complex fracture modeling
The Four Components That Deliver HiWAY Reliability
Delivering
Channel Structure
Ensuring
Structure Stability
Completion
Technique
Engineering
Design
1 ft
HiWAY is Applicable in a Broad Range of Reservoirs
 Oil, condensate-rich and gas wells
 Competent rock –
Sandstone/carbonate/shale (E/σMIN > 275)
 Requires the use of viscous fluids
 Cased hole, open hole, vertical and
horizontal wells
 BHST < 345 oF (< 174+ oC)
Reliable Design and Execution
 Engineered candidate
selection
 Design via FracCADE*
HiWAY module
 Thorough peer reviews and
design certification
 Optimized process control
using SLB standard
fracturing equipment
7
Reliable Design and Execution
 Engineered candidate
selection
 Design via FracCADE*
HiWAY module
 Thorough peer reviews and
design certification
 Optimized process control
using SLB standard
fracturing equipment
8
Reliable Design and Execution
 Engineered candidate
selection
 Design via FracCADE*
HiWAY module
 Thorough peer reviews and
design certification
 Optimized process control
using SLB standard
fracturing equipment
9
Reservoir-Focused HiWAY Design Workflow
Build
Geomechanical and
Reservoir Models
Design perforation
strategy and
pumping schedule
for optimum channel
distribution
Evaluate channel
profile and fracture
conductivity
HiWAY Execution – From Concept To Reality
Schematic pump schedule
Sand Concentration
Conventional
HiWAY
Pad
Time
Proppant (dirty) pulse
Clean Fluid (clean) pulse
Cycle
Tail-in stage
HiWAY Execution – From Concept To Reality
Actual pump schedule in typical HiWAY job
4
3
2
1
0
600
Sand Concentration, kg added/m3
Sand Concentration, PPA
5
480
360
240
120
0
11:39:43
11:46:23
11:53:03
11:59:43
HiWAY: Extensive Worldwide Experience
>5000 jobs, >99.95% jobs with proppant placed without screen-outs
HiWAY activity
New fields under discussion
2010-2012 HiWAY Activity
6000
1800
1600
5000
4000
1200
1000
3000
800
600
2000
400
1000
200
0
Q1'10 Q2'10 Q3'10 Q4'10 Q1'11 Q2'11 Q3'11 Q4'11 Q1'12
0
Cumulative stages
Stages per Quarter
1400
2010 – 2012 HiWAY Activity – Treatment (Stage) Count
Reservoir Lithology
Sandstone
Lance/Pinedale (USA)
Wamsutter (USA)
Granite wash (USA)
Yegua (Burgos basin, Mexico)
Eocene (Chicontepec, Mexico)
Sierras Blancas (Argentina)
AS & BS – (Russia)
Abrar, West Qarum (Egypt)
Gazhal (Saudi Arabia)
Others
Reservoir Fluid
Shale
229
Barnett (USA)
Haynesville (USA)
Utica (USA)
Marcellus (USA)
Bossier (USA)
Avalon (USA)
1606
3627
Carbonate
Condensate +
Gas
583
1397
3482
Eagle Ford (USA)
Bakken (USA)
Clear Fork (USA)
Well Orientation
Completion type
Vertical
392
1203
Horizontal
Oil
4259
Cased hole
5070
Open hole
Dry Gas
Case Study: Encana, Rocky Mountains
HiWAY Delivers 24% More Production from Tight Gas Formation
Challenge
 Improve production in multi-stage wells
Solution
 Improve fracture conductivity with HiWAY flow-
channe fracturing technique (13-well campaign)
Results
 24% increase in gas production
 17% increase in expected recovery after 2
years
 Reduction in screen-out rate from 5% to 0%
 +700 fracturing treatments performed to date
with significant footprint reduction
SPE Paper 140549
Formation type
TVD
Sandstone/shale
3400 – 4100 m
11,000 – 13,500 ft
Permeability
0.5 to 10 µD
Porosity
6% to 9%
Young’s modulus
24x - 41x103 MPa
3.5 - 6 million psi
BHP
28 – 69 Mpa
4,000 – 10,000 psi
BHST
79 - 118 ºC
175 – 245 ºF
Proppant/stage (Klbm)
Fluid/stage (Kgal)
HiWAY
Conventional
∆
HiWAY
Conventional
∆
162
297
-45%
94
104
-10%
Case Study: BHP-Petrohawk, Eagle Ford Shale
HiWAY Increases Production from Horizontal Well by 37%
Challenge
 Improve production in multi-stage horizontal
wells
Formation type
TVD
Solution
 Improve fracture conductivity with HiWAY
flow-channel fracturing technique (2 HiWAY
vs. 8 conventional wells)
SPE Paper 145403
3300 – 3500 m
200 to 600 nD
Porosity
6% to 8%
Young’s modulus
17x - 34x103 MPa
2.5 - 5 million psi
BHP
55 – 69 Mpa
8,000 – 10,000 psi
BHST
121 - 168 ºC
250 – 335 ºF
Gas Area
1.2
1.0
0.8
0.6
0.4
0.2
HiWAY
Conventional (best offset)
0
30
60
90
120
Time, days
150
Cumulative Oil Production (bbl)
120,000
1.4
0
10,900 – 11,500 ft
Permeability
1.6
Cumulative Gas Production (Bcf)
Results
 Heim #2H: +4 MMcfd (37%) increase in
initial gas production rate (gas window)
 Dilworth #1H: +200 BOPD (32%) increase
in initial oil production rate (oil window)
 2000+ stages, 100+ wells pumped to date
with significant footprint reduction
Carbonate/shale
180
100,000
Oil Area
80,000
60,000
40,000
20,000
0
HiWAY
Conventional (best offset)
0
Proppant/stage (Klbm)
30
60
90
120
Time, days
150
Fluid/stage (Kgal)
HiWAY
Conventional
∆
HiWAY
Conventional
∆
203
340
-40%
207
273
-24%
180
Eagle Ford Completion History





2008 – 2009, Slickwater treatments
2009 – 2010, Frac cost elevated rapidly
2010 (July), Hybrid treatments
2010 and 2011, Channel fracturing treatments
Past Direction:

Future Direction:




Lower rate, Lower pressure, Higher Viscosity
Smaller stage lengths
Sand (4 to 5 PPA) (85% -20/40 & 15% 40/70)
Reduce acid and supply water footprint




Increase viscosity
Increase contact area while minimizing cost
Lower rate, lower treating pressure
Reduce supply water footprint
Hawkville Field - Eagle Ford Shale Formation
• Eagle Ford Characteristics
• 100 – 300 ft gross thickness
• High calcite (60 - 70%)
Texas,
United States
• Low quartz (< 20%)
• Closure stress: 9,500 - 11,000 psi
• Young’s modulus: 2.7 - 4.3 Mpsi
• BHST: 275 - 335 degF
• Upper Eagle Ford
• 1 – 2.5% TOC, 4 - 7% porosity
• 150 - 300 nD permeability
• Lower Eagle Ford
• 3 – 6.5% TOC, 6 - 12% porosity
• 350 – 700 nD permeability
Mexico
Gulf of
Mexico
Hawkville Well Completions
• Well Type: Horizontal, cased hole (5½” and 4 ½” OD)
• Depth (TVD): 10,000 - 12,000 ft
• Depth (MD): 15,000 - 20,000 ft
• Horizontal Section: 4,000 - 7,000 ft
• Staging: Plug & Perf, 12 - 22 stages
• Perforation Strategy:
•
•
•
•
SPF: 4 - 6; Phasing: 60º
Cluster length: 1 - 2 ft
Clusters per stage: 4 - 8
Cluster spacing: 30 - 100 ft
Channel Fracturing (Hybrid) Treatment Plot
Distribution of Wells in the Hawkville Field
McMullen County
LaSalle County
HiWAY Channel Fracturing
Conventional – Hybrid
Conventional - Slickwater
Hawkville Field Production Data
1.6
2
Offset C
10
20
30
40
50
60
70
80
Offset B
Heim 2H
Offset A
Dilwortth1H
Offset D
90
95
98
0.1
Fracturing
technique
Range
(Bcfe)
Average
(Bcfe)
Channel
fracturing
(12 wells)
0.43 – 1.10
0.66
Hybrid
(8 wells)
0.36 – 0.65
0.50
Slickwater
(30 wells)
0.11 – 0.68
0.39
0.5
1.0
1.2
HiWAY
XL (Hybrid)
Slickwater
1
0.8
0.6
0.4
0.2
2.0
90-day cumulative production (Bcfe)
Basic completion data
(Average per well)
P50 Cumulative production (Bcfe)
Cumulative Probability
5
1.4
0
KPIs - 90 days
90 days
250 days
KPIs - 250 days
Average
Average
Production Production Production
Production Production Production
cum.
cum.
Proppant
/ 1000 ft / Mbbl
/ Mlbm
/ 1000 ft / Mbbl
/ Mlbm
production
(Mlbm) production
Lateral Frac Fluid proppant
Lateral Frac Fluid proppant
(MMcfe)
(MMcfe)
Fracturing technique
Lateral
length (ft)
Frac fluid
(Mbbl)
HiWAY (12 wells)
5755
87
3668
659
115
7.6
0.18
1,341
233
15.4
0.37
Hybrid (8 wells)
5382
99
5470
497
92
5.0
0.09
979
182
9.9
0.18
4403
176
3890
392
89
2.2
0.10
717
163
4.1
0.18
23 Slickwater (30 wells)
Productivity Normalization via Reservoir Simulations
Completion & Stimulation
Parameters*
3D Formation
Simulator
Normalized
production at
equivalent BHP
Calibrated
Model
400
XF
H
2X F
2L N + L C
LN
LC
LN
180-day normalized cumulative gas
production (MMscf/1000 ft)
350
341
300
250
200
225
175
150
160
100
50
0
Heim 2H
Offset A
(Channel Fracturing)
*Fan, L., Thompson, J., Robinson, J.R., 2010 Understanding Gas Production Mechanism and Effectiveness of Well Stimulation in the Haynesville
Shale Through Reservoir Simulation. Paper SPE 136696 presented at the Canadian Society for Unconventional Gas, Calgary 19 – 21 October
Offset B
Offset C
Dry Gas Area
180-day Cumulative Gas Production
1,600,000
Offset A
1,400,000
Heim 2H Offset A
Cumulative production (Mscf)
Offset B
Offset B
Offset C
Heim 2H (Channel fracturing)
6.6 mi
1,200,000
Offset C
1,000,000
800,000
600,000
400,000
200,000
0
0
30
60
90
120
150
180
Time, days
180-day Wellhead Flowing Pressure and Choke Size
7,000
5,000
4,000
Choke size
Wellhead flowing pressure (psi)
6,000
3,000
2,000
Heim 2H (Channel fracturing)
Offset A
Offset B
Offset C
1,000
0
0
30
60
90
Time, days
120
150
180
26
24
22
20
18
16
14
12
10
8
6
4
2
0
Heim 2H (Channel fracturing)
Offset A
Offset B
Offset C
0
30
60
90
Time, days
120
150
180
Dry Gas Area
History Matches Heim 2H
Water
Gas
BHP
Dry Gas Area
180-day Normalized Gas Production at Equivalent BHP
400
180-day normalized cumulative gas
production (MMscf/1000 ft)
350
341
300
∆ = 51%
250
200
225
175
150
160
100
50
0
Heim 2H
Offset A
(Channel Fracturing)
Offset B
Offset C
Condensate-Rich Area
180-day Cumulative Oil Production
120,000
Dilworth 1H (Channel fracturing)
Offset D
100,000
Cumulative oil production (BBL)
Dilworth 1H
Offset D
80,000
60,000
40,000
20,000
4.4 mi
0
0
30
60
90
120
150
180
150
180
Time, days
180-day Wellhead Flowing Pressure and Choke Size
6,000
Dilworth 1H (Channel fracturing)
Offset D
4,000
Choke size
Wellhead flowing pressure (psi)
5,000
3,000
2,000
1,000
0
0
20
40
60
80
100
Time, days
120
140
160
180
24
22
20
18
16
14
12
10
8
6
4
2
0
Dilworth 1H (Channel fracturing)
Offset D
0
30
60
90
120
Time, days
Condensate-Rich Area
180-day Normalized Condensate Production at Equivalent BHP
180-day normalized cumulative oil
production (Mbbl/1000 ft)
30
27.1
25
∆ = 46%
20
17.6
15
10
5
0
Dilworth 1H
(Channel Fracturing)
Offset D
Effective Stimulated Index Comparison
Condensate-Rich Area
120.00
3.00
ESI
100.00
2.50
80.00
2.00
60.00
1.50
40.00
1.00
20.00
0.50
0.00
0.00
Offset A
Offset B
Channel Frac
4.00
Prop
45.00
Fluid and Proppant Volume per Cluster (mgals, mlbs)
Fluid
Effective Stimulation Index per Cluster (ft^3.mD)
Fluid and Proppant Volume per Cluster (mgals,mlbs)
Proppant
50.00
ESI
3.60
40.00
3.20
35.00
2.80
30.00
2.40
25.00
2.00
20.00
1.60
15.00
1.20
10.00
0.80
5.00
0.40
0.00
0.00
Offset A
ESI = ESV x Enhanced Permeability
SPE Paper 149390
Fluid
ESV = 2 x PEA half-length x PEA width x thickness
Channel Frac
Effective Stimulation Index per Cluster (ft^3.mD)
Dry Gas Area
What Is The End Result?
Better production:

90-day non-normalized cumulative production increased by:

180-day normalized cumulative production:


32% (channel fracturing vs. hybrid)
68% (channel fracturing vs. slickwater).


> 51% in dry gas area;
> 46% in condensate-rich area.
Gains in efficiency:


Reduction in proppant and fluid volumes, allowing reductions in pumping time.
Over 2300 treatments (140 wells) pumped to date. Zero screenouts.
• Channel fracturing improved well performance in the Hawkville field beyond
conventional means.
• Additional completions continue to show channel fracturing treatments outperform
slickwater and hybrid in the Hawkville Field.
Public Client Endorsements for HiWAY
• BHP -Petrohawk
• Chesapeake
• Petrohunt
• Encana
• YPF, S.A.
• TNK-BP
• Rosneft
• PEMEX
• ENI
• SOG
USA - Eagle Ford shale
USA - Barnett shale
USA - Bakken shale
USA - Jonah field
Argentina
Russia
Russia
Mexico
Algeria
Egypt
HiWAY-Related Publications
Client-Endorsed SPE Activity







SPE 135034 (with YPF, S.A.) – A New Approach to Generating Fracture Conductivity (ATCE’10. Florence, Italy)
SPE 140549 (with Encana Oil and Gas USA) - Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation
(HFTC’11, The Woodlands, USA)
SPE 145403 (with PetroHawk) - Channel Fracturing in Horizontal Wellbores: the New Edge of Stimulation
Techniques in the Eagle Ford Formation (ATCE’11. Denver, USA. Oct. 2011)
SPE 147587 (with Encana Oil and Gas USA) - Raising the bar in completion practices in Jonah Field: Channel
fracturing increases gas production and improves operational efficiency (SPE UGC. Calgary, Canada. November
2011)
SPE 149390 (with Petrohawk) - Completion Evaluation of the Eagle Ford Formation with Heterogeneous Proppant
Placement (SPE UGC. Calgary, Canada. November 2011)
SPE 152112 (with PEMEX) - Field Development Study: Channel fracturing increases gas production and improves
polymer recovery in Burgos Basin, Mexico North (HFTC’12. The Woodlands, February 2012)
SPE ATW Presentation (with Rosneft)- Channel Fracturing: Experience and Applicability in Russia (Sep’10.
Nizhnevartovsk, Russia)
Industry Articles





Journal of Petroleum Technology
Hart's E&P Magazine
Petroleum (Spanish)
New Technology (Canada)
Several others
www.slb.com/hiway
2012: Integration of HiWAY modeling with
Mangrove
Structure
Lithology
HiWAY
DFN
Stress legend
High
Selectively placed perforation clusters
Rock quality
Low
Stress
StimMAP
Staging &
Perforating
Rock quality legend
Geomechanical
Model
Microseismic
Mapping
Complex Hydraulic
Fracture Models
with HiWAY
Automated
Gridding
Reservoir
Simulation
HiWAY Channel Fracturing: More value, Less Resources
• Fastest-growing new technology in the history of
Schlumberger
• > 5000 stages pumped (10 countries, 5 Areas)
• Significant impact on production
– Typically > 20% increase
• Smaller footprint: Reductions in
– water and proppant consumption per job of 25%
and 42%, respectively;
– > 6 million barrels of water and 340,000 tons of
proppant saved so far;
– > 33,000 proppant and water hauling road
journeys;
– > 4 million pounds CO2 emissions
• Unprecedented proppant placement rate:
– 99.96% placement success;
– > 200 screen-outs prevented
HiWAY: The Quest For Infinite Conductivity
Innovation for a step-change in Hydraulic Fracturing
Thank you for your attention