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HiWAY: The Quest For Infinite Conductivity Innovation for a step-change in Hydraulic Fracturing
Presentation prepared for Jornada De Maxi-Fracturas May 2012
2010
2000
1990
1980
1970
1960
1950
HiWAY: A Paradigm Shift in Hydraulic Fracturing 1947 First hydraulic fracturing job
2011 Complex fracture modeling
1950 Fracturing using gelled oil
1960 Water-based, non crosslinked fluids
1968 Borate crosslinked fluids
1973 Crosslinked derivatized guars (HPG, CMHPG, etc)
1980 Foamed fracturing
1988 Encapsulated breakers
1994 Low polymer loadings 1997 Viscoelastic surfactants (VES)
1977 High-strength ceramic proppants
2001 Micro-seismic used to monitor frac jobs 2003 Horizontal well, multistage fractures 2005 Fiber based proppant transport
1990 Fiber based flowback control
2010 HiWAY* Flow-Channel Fracturing
Ensuring Structure Stability
Engineering Design
Completion Technique
Delivering Channel Structure
The Four Components That Deliver HiWAY Reliability
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
Engineered candidate selection Design via FracCADE*
HiWAY module Thorough peer reviews and
design certification Optimized process control
using SLB standard fracturing equipment
Reliable Design and Execution
8
Engineered candidate selection Design via FracCADE*
HiWAY module Thorough peer reviews and
design certification Optimized process control
using SLB standard fracturing equipment
Reliable Design and Execution
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
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
Conventional HiWAY
Sand
Con
cent
ratio
n
Pad
Proppant (dirty) pulse Clean Fluid (clean) pulse
Cycle Tail-in stage
Time
Actual pump schedule in typical HiWAY job
11:39:43 11:46:23 11:53:03 11:59:43 0
120
240
360
480
600 Sa
nd C
once
ntra
tion,
kg ad
ded/
m3
0
1
2
3
4
5
Sand
Con
cent
ratio
n, P
PA
HiWAY Execution – From Concept To Reality
New fields under discussion HiWAY activity
HiWAY: Extensive Worldwide Experience
>5000 jobs, >99.95% jobs with proppant placed without screen-outs
2010-2012 HiWAY Activity Cumulative stages St
ages
per Q
uarte
r
0
1000
2000
3000
4000
5000
6000
0
200
400
600
800
1000
1200
1400
1600
1800
Q1'10 Q2'10 Q3'10 Q4'10 Q1'11 Q2'11 Q3'11 Q4'11 Q1'12
1203
4259
392
5070
583
1397
3482
229
3627
1606
2010 – 2012 HiWAY Activity – Treatment (Stage) Count
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 Carbonate Eagle Ford (USA) Bakken (USA) Clear Fork (USA)
Shale Barnett (USA) Haynesville (USA) Utica (USA) Marcellus (USA) Bossier (USA) Avalon (USA)
Reservoir Lithology Reservoir Fluid
Well Orientation Completion type
Oil Condensate + Gas
Dry Gas
Horizontal
Vertical
Cased hole
Open hole
Formation type Sandstone/shale TVD 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
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
Proppant/stage (Klbm) Fluid/stage (Kgal)
HiWAY Conventional ∆ HiWAY Conventional ∆
162 297 -45% 94 104 -10%
SPE Paper 145403
Challenge Improve production in multi-stage horizontal
wells
Solution Improve fracture conductivity with HiWAY
flow-channel fracturing technique (2 HiWAY vs. 8 conventional wells)
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
Case Study: BHP-Petrohawk, Eagle Ford Shale HiWAY Increases Production from Horizontal Well by 37%
Formation type Carbonate/shale TVD 3300 – 3500 m 10,900 – 11,500 ft
Permeability 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
Proppant/stage (Klbm) Fluid/stage (Kgal)
HiWAY Conventional ∆ HiWAY Conventional ∆
203 340 -40% 207 273 -24%
0.20.40.60.81.01.21.41.6
00 30 60 90 120 150 180
Time, days
HiWAYConventional (best offset)Cu
mulat
ive G
as Pr
oduc
tion (
Bcf)
0 30 60 90 120 150 180Time, days
120,000
100,000
80,000
60,000
40,000
20,000
0
Cumu
lative
Oil P
rodu
ction
(bbl)
HiWAYConventional (best offset)
Gas Area Oil Area
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: 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 Future Direction: Increase viscosity Increase contact area while minimizing cost Lower rate, lower treating pressure Reduce supply water footprint
Mexico Gulf of Mexico
Texas, United States
Hawkville Field - Eagle Ford Shale Formation • Eagle Ford Characteristics
• 100 – 300 ft gross thickness • High calcite (60 - 70%) • 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
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
Distribution of Wells in the Hawkville Field
22
McMullen CountyLaSalle County
HiWAY Channel FracturingConventional – HybridConventional - Slickwater
Hawkville Field Production Data 2
510
20304050607080
90
95
98
0.1 0.5 1.0 2.090-day cumulative production (Bcfe)
Cumu
lative
Proba
bility
Fracturingtechnique
Average (Bcfe)Range
(Bcfe)
Channel fracturing (12wells)
0.660.43 – 1.10
Hybrid(8 wells) 0.50
Slickwater(30 wells)
0.39
Heim 2H
Dilwortth1H
Offset C
Offset A
Offset B
Offset D
0.11 – 0.68
0.36 – 0.65
23
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
90 days 250 days
HiWAY
XL (Hybrid)
Slickwater
P 50 C
umul
ative
pro
duct
ion
(Bcf
e)
Basic completion data (Average per well) KPIs - 90 days KPIs - 250 days
Fracturing technique Lateral length (ft)
Frac fluid (Mbbl)
Proppant (Mlbm)
Average cum.
production (MMcfe)
Production / 1000 ft Lateral
Production / Mbbl
Frac Fluid
Production / Mlbm
proppant
Average cum.
production (MMcfe)
Production / 1000 ft Lateral
Production / Mbbl
Frac Fluid
Production / Mlbm
proppant
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
Slickwater (30 wells) 4403 176 3890 392 89 2.2 0.10 717 163 4.1 0.18
XF
2LN + LC
2XF
H
LN LC LN
Completion & Stimulation Parameters*
3D Formation Simulator
Calibrated Model
341
175 160
225
0
50
100
150
200
250
300
350
400
18
0-d
ay n
orm
aliz
ed
cu
mu
lative
ga
s
pro
du
ctio
n (M
Mscf/
10
00
ft)
Heim 2H (Channel Fracturing)
Offset A Offset B Offset C
Normalized production at
equivalent BHP
*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
Productivity Normalization via Reservoir Simulations
Dry Gas Area
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
0 30 60 90 120 150 180
Cum
ulat
ive p
rodu
ctio
n (M
scf)
Time, days
Heim 2H (Channel fracturing)Offset AOffset BOffset C
180-day Cumulative Gas Production
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 30 60 90 120 150 180
Wel
lhea
d flo
win
g pr
essu
re (p
si)
Time, days
Heim 2H (Channel fracturing)Offset AOffset BOffset C 0
2468
101214161820222426
0 30 60 90 120 150 180
Chok
e siz
e
Time, days
Heim 2H (Channel fracturing)Offset AOffset BOffset C
6.6 mi
Heim 2H Offset A
Offset B
Offset C
180-day Wellhead Flowing Pressure and Choke Size
Dry Gas Area 180-day Normalized Gas Production at Equivalent BHP
341
175 160
225
0
50
100
150
200
250
300
350
40018
0-da
y nor
mal
ized c
umul
ative
gas
prod
uctio
n (M
Msc
f/100
0 ft)
Heim 2H (Channel Fracturing)
Offset A Offset B Offset C
∆ = 51%
0
20,000
40,000
60,000
80,000
100,000
120,000
0 30 60 90 120 150 180
Cum
ulat
ive o
il pr
oduc
tion
(BBL
)
Time, days
Dilworth 1H (Channel fracturing)
Offset D
Condensate-Rich Area
0
1,000
2,000
3,000
4,000
5,000
6,000
0 20 40 60 80 100 120 140 160 180
Wel
lhea
d flo
wing
pre
ssur
e (ps
i)
Time, days
Dilworth 1H (Channel fracturing)
Offset D
02468
1012141618202224
0 30 60 90 120 150 180
Chok
e si
ze
Time, days
Dilworth 1H (Channel fracturing)Offset D
4.4 mi
Dilworth 1H
Offset D
180-day Cumulative Oil Production
180-day Wellhead Flowing Pressure and Choke Size
27.1
17.6
0
5
10
15
20
25
3018
0-da
y nor
mal
ized c
umul
ative
oil
prod
uctio
n (M
bbl/1
000 f
t)
Dilworth 1H(Channel Fracturing)
Offset D
Condensate-Rich Area
180-day Normalized Condensate Production at Equivalent BHP
∆ = 46%
Effective Stimulated Index Comparison
Dry Gas Area
0.00
0.50
1.00
1.50
2.00
2.50
3.00
0.00
20.00
40.00
60.00
80.00
100.00
120.00
Offset A Offset B Channel Frac
Effe
ctiv
e St
imul
atio
n In
dex
per C
lust
er (f
t^3.
mD)
Flui
d an
d Pr
oppa
nt V
olum
e pe
r Clu
ster
(mga
ls,m
lbs)
Proppant Fluid ESI
0.00
0.40
0.80
1.20
1.60
2.00
2.40
2.80
3.20
3.60
4.00
0.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
50.00
Offset A Channel Frac
Effe
ctiv
e St
imul
atio
n In
dex
per C
lust
er (f
t^3.
mD)
Flui
d an
d Pr
oppa
nt V
olum
e pe
r Clu
ster
(mga
ls, m
lbs)
Prop Fluid ESI
Condensate-Rich Area
ESI = ESV x Enhanced Permeability
ESV = 2 x PEA half-length x PEA width x thickness SPE Paper 149390
What Is The End Result? Better production: 90-day non-normalized cumulative production increased by: 32% (channel fracturing vs. hybrid) 68% (channel fracturing vs. slickwater). 180-day normalized cumulative production: > 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 USA - Eagle Ford shale • Chesapeake USA - Barnett shale • Petrohunt USA - Bakken shale • Encana USA - Jonah field • YPF, S.A. Argentina • TNK-BP Russia • Rosneft Russia • PEMEX Mexico • ENI Algeria • SOG 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
Structure Lithology
DFN
Geomechanical Model
Staging & Perforating
Selectively placed perforation clusters
Rock quality legend
Stress legendHigh
LowRock quality
Stress
Complex Hydraulic Fracture Models with HiWAY
Microseismic Mapping
Automated Gridding
Reservoir Simulation
2012: Integration of HiWAY modeling with Mangrove
HiWAY StimMAP
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