lessons learned unconv workshop may 2014 - coimce · lessons learned for us shale development ......

$: Lessons Learned Unconv Workshop May 2014 - COIMCE · Lessons Learned for US Shale Development ... Refrac to Improve Ultimate Recovery ... Cabot 10-Well Pad in Marcellus - Larger No$
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© 2014 BAKER HUGHES INCORPORATED. ALL RIGHTS RESERVED. TERMS AND CONDIT IONS OF USE: BY ACCEPTING THIS DOCUMENT, THE RECIPIENT AGREES THAT THE DOCUMENT TOGETHER W ITH ALL INFORMATION INCLUDED THEREIN IS THECONFIDENTIAL AND PROPRIETARY PROPERTY OF BAKER HUGHES INCORPORATED AND INCLUDES VALUABLE TRADE SECRETS AND/OR PROPRIETARY INFORMATION OF BAKER HUGHES ( COLLECTIVELY " INFORMATION") . BAKER HUGHES RETAINS ALL RIGHTSUNDER COPYRIGHT LAW S AND TRADE SECRET LAW S OF THE UNITED STATES OF AMERICA AND OTHER COUNTRIES. THE RECIPIENT FURTHER AGREES THAT THE DOCUMENT MAY NOT BE DISTRIBUTED, TRANSMITTED, COPIED OR REPRODUCED IN W HOLE ORIN PART BY ANY MEANS, ELECTRONIC, MECHANICAL , OR OTHERW ISE, W ITHOUT THE EXPRESS PRIOR W RITTEN CONSENT OF BAKER HUGHES, AND MAY NOT BE USED DIRECTLY OR INDIRECTLY IN ANY W AY DETRIMENTAL TO BAKER HUGHES’ INTEREST.

Lessons Learned

Alfredo Mendez

Business Development Director

Unconventional Resources-Eastern Hemisphere

Madrid, Spain

May 2014

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U.S. Shale Basins (TRR - 665 Tcf & 58 BBO)

23 Significant Shale Basins in U.S. - 150,000+ producing wells16,000 Wells Drilled Every Year

McClure

Wolfcamp

Bakken

Antrim

Eagle Ford

Niobraraa

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US Shale Plays

Formation Thickness - 20 - 600 ft

Depth Range - 6,500 - 13,500 ft (TVD)

Well IP’s - Gas = 2 - 10 MMcfd- Oil = 350-1800 BOPD (150-600 avg)

EUR per Well - Gas = 1.6 - 4.0 Bcf- Oil = 400 - 600 MBO

Primarily Dry Gas (Eagle Ford & Utica - Wet)

Shale Oil - Bakken*, Niobrara, Monterey, Eagle Ford, Wolfcamp (*Bakken not a shale;“shaley” LS + SS + DS - Tight Oil)

Some produce small amounts of water (Frac Flowback Water and Water Sourcing arethe major water handling concerns)

All Shales Are Not the Same - Geology, Mineralogy, Geochemistry VariesEven in the Same Basin/Play

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Developing Shale Reservoirs – US Model

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Shales must be Fracture Stimulated to produce commerciallyTwo Key Elements of shale gas development:

1. Multi-Stage Fracturing2. Horizontal Wells

(Maximize Reservoir Volume and NF’s Connected to Well)

Shale well Productivity depends on:Reservoir Quality andEffective Hydraulic Fracturing

• Vertical Wells - for reservoirdata and define play

Horizontal Wells to develop- Gas Laterals 3,000 - 6,000 ft

- Oil Laterals to 7,000 - 10,000+ ft

Well Spacing Avg. ~80 acres – Gas

~160 acres – Oil

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Number of Wells to Develop 1 TCF of Shale Gas

Shale Gas Development Requires Large Number of Wells

Shale Gas Development Requires a Large Number of Wells

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TRR - Technically Recoverable Resources

Source: EIA, Simmons and Others

Major Shale Gas Play Comparison

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Major Shale Oil Plays

TRR = Technical Recoverable Resources

Niobrara and Utica very early data

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-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Jan-81 Jan-83 Jan-85 Jan-87 Jan-89 Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09 Jan-11 Jan-13 Jan-15

Ave

rage

Dai

lyP

rod

uct

ion

Peak

mo

nth

(MC

FD)

Date

Learning Curve – Barnett Shale

8

MultistageCompletions

DirectionalVertical Horizontal

Unconventional Resource Development

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Lessons Learned for US Shale Development

Data Collection and Management is critical and needs to be planned early

Proactive engagement with operators in developing regulation (US)

Solutions depend significantly on the geology of the shale and theparticular regional characteristics

Invest in creative water management options

Logistics operating model will impact congestion and efficiency of FracSand, Water, Oil, Rig and Equipment movement

© 2013 Baker Hughes Incorporated. All Rights Reserved.9

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Baker Hughes Data-Driven ApproachAcross the Asset Life Cycle

High-Grade

Acreageand

TargetSweetSpots

Optimal

WellPlacement

DrillingPrecision

andEfficiency

TargetedFrac StagePlacement

Characterize

Lateral

OptimizeWellbore

Completion

OptimizeThe

FractureTreatment

Design

ProductionOptimization

WaterManagement

Refrac toImproveUltimateRecovery

1 2 3 4 5 6 7 8

Exploration

Appraisal

DevelopmentProduction

Rejuvenation

Asset Life Cycle

Delineating Sweet Spots / High-Grading Acreage

Optimizing Field Development / Lateral Placement

Delivering Drilling Efficiency and Precision

Characterizing The Lateral to Target Frac Placement

Optimizing The Fracture Design

Selecting Effective Wellbore Completions

Monitoring and Refining Fracture Stimulation

Maintaining Continuous Production Flow and

Managing The Water Cycle

Refracturing To Improve Ultimate Recovery

“Steps to Success - Increased Recovery”

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Multi-Well Pads Drive Long-Term Success

Statistical Drilling Multi-Well Pad Drilling

• Shale wells must be drilledin the direction of SH MIN

• Wells per Pad

- Typically 2 to 6 wells- Max ≈ 10 wells- Larger No. Wells - DualsCabot 10-Well Pad in Marcellus

Pad Drilling Used in Development Drilling – Need Geologic Data to Select Pad LocationCannot be used for Exploration/Appraisal

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Benefits of Pad Drilling

Environmental– Dramatically minimize surface disturbance (consolidation of surface

drilling and production equipment)

– Reduces an Operator’s impact on developable land

– Minimizes wildlife disturbance

– Requires fewer access roads to multiple pads (single wells) vs singlepad for multiple wells

– Reduced truck traffic (emissions)

– In populated areas – smaller surface footprint better communityrelations

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Environment Constrain – Traffic

133,950 1,810

Horizontal 3X Vertical

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Hydraulic Fracturing

• Logistics for Hydraulic Fracturing is the Major Concern

Significant Equipment and Materials

- Pump Trucks: Approx 15,000 to 20,000 HHP typical Job

- Water = 1,000 bbl frac Fluid/Stage + Site Storage

(Total Well = 15,000 bbls)

- Sand/Proppant = 320,000 lbm /Stage + Site Storage

(Total Well = 4.8 Mil lbms = 2,400 Tons)

• US Water Trucked, Proppant Trucked or Rail car (track/line) Pump Trucks, andStorage Tanks via Road

• Rail In Eagle Ford Shale (Next Slide)

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Three Principal Components of Costs of Water Management (USCosts)

1. Acquisition Costs($0.25/bbl - $1.75/bbl)

• Sourcing costs to acquire fresh water fromsurface waters, ground water and municipalstorage

• These Costs tend to be consistent betweendifferent resource plays. Bakken has seengreatest inflation in sourcing costs.

2. Hauling Costs($0.63/bbl - $10.00/bbl)

• Includes Transporting Sourced Water toWell and Flowback / Produced Water toDisposal

• These Costs tend to be most variablebetween resource plays. Marcellus haulingcosts higher due to strong regulations.

3. Disposal Costs($0.50/bbl - $3.00/bbl)

• Disposal Costs vary between resourceplays and are generally supported bystrong regulations.

Apache 50 Wolfcamp Shale Wells

• Water Source brackish water from SantaRosa aquifer and recycled flowback andproduced water

• $0.29/bbl - Treat Flowback Wtr• $2.50/bbl - Disposal costs

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What to do?

Begin with the Hydraulic Fracturing in Mind!

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In order to get long/bigger fractures:

•Improve fluid loss control

•Increase the pumping rate•Higher Friction•Higher Net pressure•More HHP•More than 15 K psi

High Frac Fluid Leak Off

BHFP

Q

Q leakoff

V Fracture = t * (Q-Q leakoff) = V pumped - V leaked

Q Leakoff - f (Cw, DP, Lf, etc)

Usual Gradientsat 16,000 ft

Frac: 0.7 - 0.95 psi/ft

Pore: 0.3 - 0.35 psi/ft

Very low fluid efficiency – Short/SmallFractures

The issues!

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Bring the Gorillas

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20,000 PSI Iron

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First Campaign

# WellRATE

bpm

STP

psi

StressGrad.

psi/ft

FE

%

BHTPpsi

HSP lbs

Surf. Bottom

Max. Conc.

Ppa

1 I 33 15,240 0.95 6.3 18,500 190,300 185,400 8 / 8

2 I 42 15,000 0.75 5.9 18,500 181,600 168,000 8 / 6.4

3 II 41 13,500 0.67 11 17,500 408,600 398,000 11 / 11

4 II 39 16,500 0.74 8 25,000 433,000 389,600 8 / 8

5 III 35 14,250 0.93 14 18,200 99,400 68,700 5.8 / 5.4

6 IV 35 15,500 0.96 15 17,000 137,400 125,100 6.2 / 6.2

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Actual Jobs

15,200 PSI

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Petrophysics: “Shales” have variable mineralogy…

© 2009 Baker Hughes Incorporated. All Rights Reserved.

BarnettHaynesvilleMontney MarcellusEagle Ford

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Characterize the Lateral for Completion Optimization

Optimized locations for frac stages

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Unconventional Shale Reservoir Petrophysical Evaluation:Lateral Characterization

Currently only a few operators are acquiring petrophysical, geological or geomechanical information inhorizontal laterals.

Those who have reported improved well productivity from more effective stimulation and completionperformance.

The most frequently used technology is LWD resistivity Imaging.

© 2012 Baker Hughes Incorporated. All Rights Reserved.2

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Geological Characterization: StarTrak Analysis in Horizontal Lateral to Optimize Stimulationand Completion Performance

© 2012 Baker Hughes2

Open Fractures

Partial Fractures

Shear Fractures

Faults

Open Fractures

Partial Fractures

Shear Fractures

Faults

Stages

WellborePath

Gamma RayModel

Gamma RayReal-time

Static ResistivityImage

Depth (ft)

Dip, Angle

Gamma

7,000 8,750 9,000 9,250 9,5007,750 8,000 8,250 8,5007,250 7,500

8 6 5 4 3 2 17

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Niobrara Completion Study

Electrical Image

Completion Stages

RNS Correlation

Production

Stimulation Summary

91013 111215 14 2345678 1

Lower in zone =Better Frac

5% of Production20% of Frac Dollars

Higher in Zone not as productive



Comparing Electrical Images, Production by Stage, and Frac Dollars

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Completion Recommendations

Isolate faultLower volume fracture

Isolate fault

15 4 3 210 9 8 7 6

Move sleeve towards lower packerTail in with higher ppg sandWalk away?

Aggressive tie-inHigher PPG

Combine Stages

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Relating stage contributions to production: Impact on FieldDevelopment Plan

Rates measured by PLT 5 months later

7 6 5 4 3 2 189

302520151050

13 247 5689

Naturalfractures

Events

lessons learned unconv workshop may 2014 - coimce · lessons learned for us shale development ......

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