HiWAY: The Quest For Infinite Conductivity Innovation for a step-change in Hydraulic Fracturing

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 1947 First hydraulic fracturing job 1950 Fracturing using gelled oil 1960 1960 Water-based, non crosslinked fluids 1970 1980 1990 2000 2010 1968 Borate crosslinked fluids 1973 Crosslinked derivatized guars (HPG, CMHPG, etc) 1977 High-strength ceramic proppants 1980 Foamed fracturing 1988 Encapsulated breakers 1990 Fiber based flowback control 1994 Low polymer loadings 1997 Viscoelastic surfactants (VES) 2001 Micro-seismic used to monitor frac jobs 2003 Horizontal well, multistage fractures 2005 Fiber based proppant transport 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/σ MIN > 275) Requires the use of viscous fluids Cased hole, open hole, vertical and horizontal wells BHST < 345 o F (< 174 + o C)

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 Conventional HiWAY Sand Concentration Pad Proppant (dirty) pulse Clean Fluid (clean) pulse Cycle Time Tail-in stage

HiWAY Execution From Concept To Reality Actual pump schedule in typical HiWAY job Sand Concentration, PPA 5 4 3 2 1 0 Sand Concentration, kg added/m 3 600 480 360 240 120 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 1800 1600 1400 6000 5000 Stages per Quarter 1200 1000 800 600 4000 3000 2000 Cumulative stages 400 200 1000 0 Q1'10 Q2'10 Q3'10 Q4'10 Q1'11 Q2'11 Q3'11 Q4'11 Q1'12 0

2010 2012 HiWAY Activity Treatment (Stage) Count Reservoir Lithology Reservoir Fluid 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 1606 229 3627 Shale Barnett (USA) Haynesville (USA) Utica (USA) Marcellus (USA) Bossier (USA) Avalon (USA) Carbonate Eagle Ford (USA) Bakken (USA) Clear Fork (USA) Condensate + Gas 3482 583 Oil 1397 Dry Gas Well Orientation Completion type Vertical 392 Open hole 1203 Horizontal 4259 Cased hole 5070

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 flowchanne 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 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 - 41x10 3 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 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 SPE Paper 145403 Cumulative Gas Production (Bcf) 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 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 - 34x10 3 MPa 2.5-5 million psi BHP 55 69 Mpa 8,000 10,000 psi BHST 121-168 ºC 250 335 ºF Gas Area HiWAY Conventional (best offset) 0 0 30 60 90 120 150 180 Time, days Proppant/stage (Klbm) Cumulative Oil Production (bbl) 120,000 100,000 80,000 60,000 40,000 Oil Area 20,000 HiWAY Conventional (best offset) 0 0 30 60 90 120 150 180 Time, days Fluid/stage (Kgal) HiWAY Conventional HiWAY Conventional 203 340-40% 207 273-24%

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

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 Texas, United States 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 LaSalle County McMullen County HiWAY Channel Fracturing Conventional Hybrid Conventional - Slickwater

Hawkville Field Production Data Cumulative Probability 2 5 10 20 30 40 50 60 70 80 90 95 98 Offset C Offset B Offset A Offset D Fracturing technique Channel fracturing (12wells) Hybrid (8 wells) Slickwater (30 wells) Range (Bcfe) Heim 2H 0.43 1.10 0.36 0.65 0.11 0.68 Dilwortth1H Average (Bcfe) 0.1 0.5 1.0 2.0 90-day cumulative production (Bcfe) 0.66 0.50 0.39 P 50 Cumulative production (Bcfe) 1.6 1.4 1.2 1 0.8 0.6 0.4 0.2 0 HiWAY XL (Hybrid) Slickwater 90 days 250 days Fracturing technique Lateral length (ft) Basic completion data (Average per well) Frac fluid (Mbbl) Proppant (Mlbm) Average cum. production (MMcfe) KPIs - 90 days Production / 1000 ft Lateral Production / Mbbl Frac Fluid Production / Mlbm proppant Average cum. production (MMcfe) KPIs - 250 days 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 23 Slickwater (30 wells) 4403 176 3890 392 89 2.2 0.10 717 163 4.1 0.18

Productivity Normalization via Reservoir Simulations Completion & Stimulation Parameters* 3D Formation Simulator Calibrated Model Normalized production at equivalent BHP 400 350 341 2L N + L C 2X F H X F L N L C L N 180-day normalized cumulative gas production (MMscf/1000 ft) 300 250 200 150 100 50 0 175 160 225 Heim 2H (Channel Fracturing) Offset A Offset B Offset C *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

Dry Gas Area Heim 2H Offset A Offset B Offset C 6.6 mi Cumulative production (Mscf) 180-day Cumulative Gas Production 1,600,000 Heim 2H (Channel fracturing) 1,400,000 Offset A Offset B 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 Wellhead flowing pressure (psi) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Heim 2H (Channel fracturing) Offset A Offset B Offset C 0 30 60 90 120 150 180 Time, days Choke size 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 90 120 150 180 Time, days

Dry Gas Area History Matches Heim 2H Water Gas BHP

Dry Gas Area 180-day Normalized Gas Production at Equivalent BHP 400 350 341 180-day normalized cumulative gas production (MMscf/1000 ft) 300 250 200 150 100 50 175 160 225 = 51% 0 Heim 2H (Channel Fracturing) Offset A Offset B Offset C

Condensate-Rich Area Dilworth 1H Offset D 4.4 mi Cumulative oil production (BBL) 180-day Cumulative Oil Production 120,000 Dilworth 1H (Channel fracturing) Offset D 100,000 80,000 60,000 40,000 20,000 0 0 30 60 90 120 150 180 Time, days 180-day Wellhead Flowing Pressure and Choke Size Wellhead flowing pressure (psi) 6,000 5,000 4,000 3,000 2,000 1,000 0 Dilworth 1H (Channel fracturing) Offset D 0 20 40 60 80 100 120 140 160 180 Time, days Choke size 24 22 20 18 16 14 12 10 8 6 4 2 0 Dilworth 1H (Channel fracturing) Offset D 0 30 60 90 120 150 180 Time, days

Condensate-Rich Area 180-day Normalized Condensate Production at Equivalent BHP 30 27.1 180-day normalized cumulative oil production (Mbbl/1000 ft) 25 20 15 10 5 17.6 = 46% 0 Dilworth 1H (Channel Fracturing) Offset D

Effective Stimulated Index Comparison Dry Gas Area Condensate-Rich Area 120.00 3.00 50.00 4.00 Proppant Fluid ESI 45.00 Prop Fluid ESI 3.60 Fluid and Proppant Volume per Cluster (mgals,mlbs) 100.00 80.00 60.00 40.00 20.00 2.50 2.00 1.50 1.00 0.50 Effective Stimulation Index per Cluster (ft^3.md) Fluid and Proppant Volume per Cluster (mgals, mlbs) 40.00 35.00 30.00 25.00 20.00 15.00 10.00 5.00 3.20 2.80 2.40 2.00 1.60 1.20 0.80 0.40 Effective Stimulation Index per Cluster (ft^3.md) 0.00 Offset A Offset B Channel Frac 0.00 0.00 Offset A Channel Frac 0.00 ESI = ESV x Enhanced Permeability SPE Paper 149390 ESV = 2 x PEA half-length x PEA width x thickness

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 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 DFN HiWAY StimMAP Stress legend High Low Selectively placed perforation clusters Rock quality Staging & Perforating Stress Rock quality legend Geomechanical Model Complex Hydraulic Fracture Models with HiWAY Automated Gridding Microseismic Mapping 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 CO 2 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