Shale

Jason PitcherDirector

Global Technical Solutions

Shale Field Development Path (Front End Loaded)

Full Field Integration, Visualization and OptimizationVisualization and Optimization

Variables used for basin comparison Vitrinite reflectance (%Ro) - maturity

Total organic carbon (TOC)richness•Gas in place (scf/ton)

Areasq km

Net Thick. m.

This information is AvThe figure is comprised of six axes.generally available in the published literature

Av. Depth. m

g pEach is defined by 0 and the maximum value for the variable Modified by JLGevirtz to accommodate more axes /parameters

“Magnificent Five” Shale Plays ‐ Variables used for basin comparison

Core

*This information is generally available in the published literature

Core

Magnificent Five Shale Plays ‐ Variables used for basin comparison

Core

*This information is generally available in the published literature

Core

Shale gas risk plot derived from known US shale plays(as template for accelerated evaluation)

Area of minimum requirementfor successful shale play based

Ro

(as template for accelerated evaluation)

for successful shale play based on descriptive parameters for productive US shale plays.TOCGIP

scf/t

The approximate probability of success is lower as the number of points fall inside the gray area increases.

Areak

Net hi k

MarcellusBarnett

sq km Thick. m. HaynesvilleWoodfordFayetteville

Area of minimum requirementAv. Depth. m

…and Made ~60 Global Basin Comparisons

Appraisal of Shale Potential

Petrophysics Multiple Well Scenario Analysis Productivity Modeling (Becoming Absolute)

Pil t P Pilot Programs Micro-seismic

‘Sweet Spot’ Initial Identification

Basin Modeling

Tier definition-Maturity-TOC-SW-PorosityPorosity,Etc. etc.

Regional Geology, Geophysics and

Detailed Geocellular Modeling, p y

petrophysics Pilot Program

Shale Petrophysics

Lithology Unconfined C

ReservoirProperties

Brittleor

D til ?

Compressive Strength

Mineralology

NaturalDuctile? Natural Fractures?

ShaleType Hydrocarbon

C t typ

Frac“Ease”

Kerogen ContentTOC

Content

SPE 115258

Core Analytical Program

Porosity and permeability (tight gas sandstones)

Gas desorption and content

Organic richness

Mineralogy (calibrate GEMTM for vertical wells and LaserStrat® for horizontal wells))

Elemental composition and chemostratigraphic correlation

Fracture characterization

Mechanical propertiesTM

11

Fluid sensitivity – ShaleEvalTM

TOC Facies

Brittleness Conditioned to Facies

Porosity Conditioned to Brittleness and Facies

Porosity Conditioned to Brittleness and Facies

Frac Design Modeling

MShale

16

What Do We Really Know?

© 2011 HALLIBURTON. ALL RIGHTS RESERVED. 17

Current Barnett Frac Stage Averages

4000 ft laterals Stage Span = +400 ft

Stage size 15 500 BBL/stagegal ppg prop lbs rate time

pad 100000 80 29.76 Stage size = 15,500 BBL/stage Prop Volume = 430,000 lbs/stage Number of stages 6--8 Prop type: 60% 100 mesh

pad 100000 80 29.76slurry 40000 0.3 100 mesh 12000 80 12.07slurry 40000 0.5 100 mesh 20000 80 12.18slurry 100000 0.6 100 mesh 60000 80 30.58slurry 100000 0.7 100 mesh 70000 80 30.71p yp

40% 40/70 Rate = 70 BPM End Conc = 2 ppg Treating Pressure = 4000 psi

slurry 100000 0.8 100 mesh 80000 80 30.85slurry 100000 1 40/70 100000 80 31.12slurry 70000 1.25 40/70 87500 80 22.02flush 12000 80 3.57

Treating Pressure = 4000 psi SRV (ft3)= 4/3*π*ABC

A=network widthB=Frac length

% 100 mesh 56.34% total lbs 429500 lbs% 40/70 43.66% total time hr 3.38 hr% pad 15.38%

C=Height/2 avg ppg 0.66 ppg

lbs 100 mesh 242000 lbslbs 40/70 187500 lbstotal volume 650000 gal 15,476 BBL

EAGLE FORD Fracture Stimulation Trends

WaterFracs Hybrid/Conv 12-15 Stages

8-10 Stages 80-100 BPM

1 5 MM lb

40-60 BPM 3-4 MMlbs prop

(total) 30/60 20/40 1.5 MM lbs prop

100 Mesh, 40/70 1 ppg Max

30/60, 20/40 3-4 ppg 4 MM Gal 25,000 HHP1 ppg Max

7 MM Gal 40,000 HHP

250-300’/Stage

2008 2009 2010

, 350-450’/Stage

2008 2009 2010

Major Shale Plays in North America

Ref: EIA

Comparison of Selected USA shale playsBarnett

(oil & gas)Haynesville

(gas)Marcellus(oil & gas)

Eagle Ford(oil & gas)

Bakken(oil - 40º+ API)

Estimated basin area (sq. 5 000 9 000 95 000 Potentially very 2000+Estimated basin area (sq. mi.)

5,000 9,000 95,000 Potentially very large

2000+

Total vertical depth (ft) 5,400 – 9,500 10,500 – 13,500 4,500 - 8,000 5,000 - 12,000 3,000 - 11,000

Thickness (ft) 100 - 500 60 - 350 50 - 300 100-250 6-15ft & 80-145 ft

Bottom hole temperature (BHT)

150° F 280-380º F 100º F-140º F 150° - 350º F 190° - 240º F

TOC (%) 4-8% 2-5% 3-10% 2-9% Upper-11%-40%Lower=8%-21%

Ro 0 08 2 0 1 7 2 5 0 8 3 0 1 0 1 45 < 1Ro 0.08 – 2.0 1.7 - 2.5 0.8 - 3.0 1.0 - 1.45 < 1

Pressure Gradient (psi/ft) 0.52 0.85 - 0.93 0.4 - 0.6 0.4 - 0.65 0.5 - 0.8

Porosity 4.0 - 9.6% 8 - 15% 4 - 6% 3.4 - 14.6% 2 - 12 %

OGIP/ ti (b f ) 100 300 150 250 70 150 40 223 5 9 MM bblOGIP/section (bcfe) 100 - 300 150 - 250 70 - 150 40 - 223 5-9 MM bbls

Horizontal well cost ($ M) 2.5 - 4.5 6-10 3 - 4 5 - 10 -

EUR (Bcfe/Well) 2.0 – 3.5 4.0 - 7.5 3 - 6 3 - 6 500,000+ bbl

Sources: D.O.E, Halliburton, Raymond James, and publicly available

BARNETT SHALE OVERVIEW

Top 10 richest Hydrocarbon Plays 4th Largest Gas play in World 9.0 Tcf produced

5 7 B f/D d ti 5.7 Bcf/D production EUR is ~55+ Tcf potentially

Barnett Well Completions

15,300+ well completions in 25 counties (as of 09/2011)

+11000 Horizontals

+4000 Verticals

23 counties

+11000 Horizontals

+4000 Verticals

25 counties

Oil wells - greenGas Wells - red

Drilling Permits blue 23 counties 25 counties Drilling Permits - blue

EAGLE FORD

Outcrop near DallasOutcrop near Dallas

Source: Texas RRC

© 2011 HALLIBURTON. ALL RIGHTS RESERVED. 28

Shale Investment Framework

I t t• Strategy• Growth• Maintenance• Monetize

• Economic HurdlesTime Horizon

• Low Geologic • High Mechanical• High CommercialTi i & C t C t l

Risk • Risk Tolerance• Strategic Importance• Liquidity• Political Stability• Resource Availability

Capital Equipment

Investment Decision

• Time Horizon• Liquidity and Capital Capacity

Return Objectives

• Timing & Cost Control• Commodity Price

• Capital Equipment• Skilled Labor

Constraints

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Unique Lifecycle Risks - Unconventional

Pilot Program High Grading Determine homogeneity

– Goals:– Test geologic hypothesis

T t h i l h th i

Determine homogeneity of source rock through land position

– Test mechanical hypothesis– Test stimulation technique– Determine commercial potential

– Sweet Spots (Bakken)– Hydrocarbon Windows

(Eagle Ford)Determine commercial potential

Lower “conventional” geologic risk, but high

(Eagle Ford)– Commerciality Tiers

(Barnett Shale)g g , gcommerciality risk– High producability uncertainty

Cost to understand producability

Post Pilot (Additional– High development cost uncertainty Pilot program can involve many more wells than typical

conventional exploration program31

– Post Pilot (Additional Seismic)

– During Drilling (Frac &

Unique Lifecycle Risks - Unconventional

Development Secondary Stimulation Long life asset lends itself

Limited reservoir drive mechanism results in need for artificial lift and higher drilling density

Large development capital requirements

Long life asset lends itself to high option value from future technology inno ation in reco er Large development capital requirements

Constant drilling operations to maintain field production level

innovation in recovery techniques

Low primary recovery Drilling PUDs and refining decline parameters to move

Probable to Proved reservesF i f l

p y yfactor and nature of hydrocarbon flow provides potential high Focus on economies of scale

– Infrastructure costs reasonably known– Learning curve achievement

provides potential high marginal economic value creation from secondary

f– Learning curve achievement– Focus on costs control and capital efficiencies

• Drive financial and operational KPIs32

hydraulic fracture stimulation treatments “refracs”

Type Curves

33

Investment Timeline

34

Multi-well P50 Development Plan

35

Multi-well P50 Development Plan

36

International Shale Investment Issues

Infrastructure– Product Pipelines

• “Marketability of Product”Oilfi ld S i E i t A il bilit– Oilfield Services Equipment Availability

• Appropriate Land Rigs• Fracture Stimulation EquipmentFracture Stimulation Equipment• Capacity Utilization of Equipment Drives Market

Prices Production Tests

– Ability to Flare Gas Right to Land Usage

– Surface rights are negotiated in USImminent Domain

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Summary

Unconventional Gas requires a comprehensive approach d ti l ti d l tiaround stimulation and completion

Wells must be drilled and constructed to– Wells must be drilled and constructed to accommodate the most rigorous anticipated treating conditions.

– Completions must be designed to maximize reservoir contactcontact.

– A keen understanding of the reservoir, geology,A keen understanding of the reservoir, geology, petrophysics, geomechanics, geochemistry, tectonics, etc. is required.

© 2012 HALLIBURTON. ALL RIGHTS RESERVED.

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GraciasMerciJason Pitcher

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Jason PitcherHalliburton

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