Devon Energy Overview - ALRDC Files... · Devon Energy Overview Todd Moehlenbrock, Vice President – Engineering Technology ... DVN Slide 11 (40% Oil & Liquids) Resource By Asset

Devon Energy OverviewDevon Energy OverviewTodd Moehlenbrock, Vice President – Engineering Technology

2012 International Sucker Rod Pumping WorkshopSeptember 27, 2012

Rotaflex

Texaco’s first Rotaflex installation

B F Harrison B #1B.F. Harrison B #1North Teague FieldSouth of Eunice, New Mexico

Your humble presenter!

NYSE: DVN www.devonenergy.com page 2

Devon History

• Founded as a private company in 1971

• Became a public company in 1988

• Currently listed on the New York Stock yExchange under the ticker symbol DVN

• Has grown from 185 employees in 1981 to more than 5 000 employees todayto more than 5,000 employees today

• Established a portfolio to provide stable production and a solid platform for future growth


Top Oklahoma companies Enterprise valueUS$, Billions


Note: Enterprise value – August 2012.

Mergers & Acquisitions

$Ocean Energy Chief

$5.3 billion2003

$2.2 billion2006

Mitchell Energy P g$3.5 billion

2002$2.6 billion

1999

Mitchell Energy

A d

Pennzenergy

Northstar L

$4.6 billion2001

$759 million1998

Anderson Exploration

Northstar Energy

2001

$3.5 billionNorth American Onshore Assets

$254 million

Santa Fe Snyder Kerr-McGee

2000$254 million

1996

Employment centers

Oklahoma City:C t H d tCALGARY Corporate Headquarters1,648 employees

Calgary, Alberta:1,004 employees

Houston:495 employees

OKLAHOMA CITY

p y

Field Offices:2,222 employees

HOUSTON

Total:~5400 employees


Current as of February 2012

Devon Today

Horn River Oil

Proved reserves: 3.0 billion BOE(42% liquids)

Q2 2012 production: 679 MBOED

JackfishPike

Ferrier CorridorDeep Basin

Liquids-Rich

Dry Gas

Production mix: 22% oil

15% NGLsR ki

MichiganPowder River

63% natural gas

Significant midstream businessGranite Wash

Cana WoodfordMississippian

RockiesOil Utica Ohio

g

Washakie

2012e operating profit: ≈$385 million

Enterprise value: $25 billion

GBarnett Shale

Permian Basin Tuscaloosa Shale

Haynesville/BossierCarthage

Groesbeck

NYSE: DVN www.devonenergy.com Slide 7

Carthage

Devon’s Strengths

Disciplined focus on per share resultsDisciplined focus on per share results

Deep inventory of development opportunitiesp y p pp

Strong, highly-visible oil growth

Significant positions in emerging oil plays

Superior financial strength and flexibility


Track Record of SuccessNorth American Onshore Historical Performance

240Production Growth

(MMBOE)LOE per BOE

($/BOE)

223220

207

182

$6.54$7.32

$8.06$6.87 $7.32 $7.71

168

2006 2007 2008 2009 2010 2011 2006 2007 2008 2009 2010 2011

233%198%

269%223% $10.01

$11.68$13.36

$10.88$11.59$12.87

Drill-Bit Reserve Replacement(1)

(% of Production Replaced)Drill-Bit F&D (3 Yr Avg.)(1)

($/BOE)

198%175% 160%

$10.01


2006 2007 2008 2009 2010 2011 2006 2007 2008 2009 2010 2011

(1) Excludes price revisionsNote: Includes a non-GAAP measure, see appendix for required disclosures.

Significant Oil Production GrowthNorth American Onshore

148 6

Production Data in MBOPD

148.6

122.5

105 9105.9100.9

89.7

74.965 765.7


2006 2007 2008 2009 2010 2011 Q2-2012

2012 Capital ProgramDelivering Strong Oil & Liquids Growth

2012e Exit Rate Oil productionOil production

Oil

2012e Exit Rate Oil productionOil production• Annual growth rate: 22% - 24%• Driven by Jackfish and Permian• ≈25% of total company volumes

NGLs productionNGLs productionOil24%

NGLs productionNGLs production• Annual growth rate: 11% - 13%• Driven by Cana and Barnett activity• NGLs have access to Mont Belvieu

N l d iN l d iGas59% NGLs

17%

Natural gas productionNatural gas production• Expect minor declines• No dry gas rigs running• No significant lease expirations

≈710 MBOED


(40% Oil & Liquids)

Resource By AssetStrong Foundation for Growth

Unrisked Proved Additional Risked Total Risked

Data in BBOE

+Resource Reserves Risked Potential Resources

Permian Basin 7.6 0.2 2.6 2.8

B tt Sh l 4 3 1 2 1 3 2 5

+ =

Barnett Shale 4.3 1.2 1.3 2.5

Cana Woodford Shale 2.8 0.3 1.6 1.9

Canadian Oil Sands 2.1 0.5 0.9 1.4

East Texas/Gulf Coast 0.9 0.2 0.6 0.8

Other U.S. 4.6 0.4 1.7 2.1

Other Canada 3 3 0 2 1 8 2 0Other Canada 3.3 0.2 1.8 2.0

Horn River 1.4 - 1.1 1.1

Sinopec JV Assets (net) 4.8 - 1.6 1.6


Total 31.8 3.0 13.2 16.2

Growing the Resource BaseNew Ventures Exploration

Sinopec Joint VentureSinopec Joint VentureSinopec Joint VentureSinopec Joint Venture• $2.5 billion transaction

($900 million cash and $1.6 billion drilling carry)

• Sinopec receives 33% of Devon’s interest

Rockies OilMichigan

• Net acreage in joint venture: 1.5 million

• Devon serves as operator

Mississippian

Rockies OilUtica Ohio Sumitomo Joint VentureSumitomo Joint Venture

• $1.4 billion transaction ($340 million cash and $1.025 billion drilling carry)

• Sumitomo receives 30% of Devon’s interest

Tuscaloosa Shale

• Sumitomo receives 30% of Devon s interest

• Net acreage in joint venture: 650,000

• Devon serves as operator

Cline Shale & Wolfcamp Shale


Sinopec joint venture assets

Sumitomo joint venture assets

Joint Venture Rationale

Objective: Utilize partnerships in new ventures explorationObjective: Utilize partnerships in new ventures exploration

• Improves capital efficiency

• Accelerates de-risking and commercialization

• Mitigates exploration risk

• Flexibility to generate new prospects

• Preserves cash flow for development projectsp p j


Permian Basin OverviewOil Opportunities

Net risked resource: 2.8 BBOENEW MEXICO OKLAHOMA

Risked locations: >8,000

Net acreage: 1.5 million basin-wide

TEXAS

MidlandNorthwestern

New

Mex

ico

Texa

s

Eastern

Shelf

Q2 2012 net production: 59 MBOED(76% liquids)

A ti it t g ti g l l t

MidlandBasinShelf

WolfberryBone Spring& Delaware

Shelf

Cline ShaleActivity targeting several play types

Expect >30% oil growth in 2012

20 operated rigs

Central BasinPlatform

MidlandWolfcamp(Delaware)

20 operated rigs

2012 capital: ≈$1.4 billion

2012 plans: Drill >300 wellsOzona ArchDiablo

Conventional Wolfcamp(Midland)


2012 plans: Drill >300 wells

NYSE: DVN

Ozona ArchDiabloPlatform

Permian Basin Oil Development Projects

oNW Sh lf

Development OverviewDevelopment OverviewL i k hi h i il l

WolfberryGaines Dawson

Lea

Eddy

New

Mex

ico

Texa

s

NW Shelf • Low-risk, high-margin oil plays• Multi-year drilling inventory

• 16 operated rigs

Midland

Andrews MartinBone Spring& Delaware

Bone Spring/DelawareBone Spring/Delaware• 185,000 net acres (2012 plans: Drill ≈110 wells)

• High-impact wells (Best wells: IP’s >1,000 BOED)Midland

MidlandEctorWinkler

Ward

LovingWolfberryWolfberry• 160,000 net acres (2012 plans: Drill ≈100 wells)

• Upside: Downspacing and Wolfcamp h i l l i i

Conventional

UptonCrane

Ward

Reeves

horizontal exploitation

Other Conventional ActivityOther Conventional Activity• Exploit Central Basin Platform targets

S k d il Pecos

• Stacked oil pays(Tubb, Wichita-Albany, Strawn, Clear Fork & others)


Permian Basin Oil Exploration Projects

Exploration OverviewExploration Overview

Gaines Dawson Borden Scurry Fisher

• Potential, high-impact resource plays(Unrisked resource: >3 BBOE net to Devon)

• 2012 plans: Drill ≈40 wells

• 4 operated rigs

Midland

Andrews Martin Howard Mitchell Nolan

Cline Shale

4 operated rigs

Cline ShaleCline Shale• JV acreage: 556,000 net acres

(Net to Devon: 389,000 acres)

MidlandEctor Glasscock SterlingCoke

TomGreenU t

Crane

• Stacked pay potential

• Encouraging initial well result

MidlandMidland--Wolfcamp ShaleWolfcamp Shale

Wolfcamp Shale(Midland Basin)

Green

Irion

SchleicherCrockett

ReaganUpton MidlandMidland Wolfcamp ShaleWolfcamp Shale

• JV acreage: 94,000 net acres (Net to Devon: 66,000 acres)

• Well results continue to improve Crockett

• Testing longer laterals (Extending to >7,000’)


MississippianLight-Oil Exploration

K

SumnerHarper

Barber

Kingman

Cowley

Sedgwick

Net acreage: 545,000 (400,000 net acres outside of Sinopec JV)

High-margin exploration playOklahoma

Kansas

Osage

KayGrant

AlfalfaWoods

High margin, exploration play

Early results in-line with expectations

Creek

GarfieldMajor

Payne

PawneeNoble

Risked resource potential: >800 MMBOE

Stacked pay potential (Woodford)

Logan

Lincoln

Creek

Devon Acreage

D /Si JV A

7 operated rigs

2012 plans: Drill >50 wellsDevon/Sinopec JV Acreage


Devon’s Thermal Oil Position SAGD Development

Field characteristicsField characteristicsJ kfi h

• Low F&D• Flat production profile• Long reserve life >20 years

Jackfish 2

Jackfish 3

Jackfish

JackfishJackfish• Top-tier operating performance• Q2 2012 net production: 33 MBOPD

Jackfish 2Jackfish 2

• Q2 2012 net production: 18 MBOPD• Reach peak facility capacity in 2013

Jackfish 3Jackfish 3• Construction ≈40% complete

PikePike• Up to five SAGD development phases

Jackfish (100% WI)

Pike (50% WI)

Access Pipeline• Up to five SAGD development phases• First regulatory application filed in June


Long-Term Production OutlookThermal OilNet Barrels Per Day

175,000

150,000

Net Risked Resource: ≈1.4 BBO

51,100


Q2 2012 2020

Cana Woodford ShaleLiquids-Rich Gas Development

Net risked resource: 11.4 TCFEOKLAHOMA

Dewey Blaine Risked locations: ≈5,400

Net acreage: 244,000

L lt b d 21%

TEXAS

Custer

Canadian

Low average royalty burden: 21%

Q2 2012 net production: 280 MMCFED

2012 40% f d ti i li id

Washita

Cana Plant

2012e program: >40% of production is liquids

Expanding gas processing facility:• 30 MBPD of NGL capacity

Significant undrilled liquids-rich inventory• ≈3,000 locations

2012 plans: Drill 200 wellsCaddo Grady


2012 plans: Drill ≈200 wells

Barnett ShaleLiquids-Rich Gas Development

Net risked resource: 14.8 TCFE

Ri k d l ti 5 000Jack Wise Denton

Net acreage: 624,000


Risked locations: ≈ 5,000

Denton

Bridgeport Plant


Q2 2012 net production: 1.32 BCFED

2012e program: >30% of production is liquids

ParkerPalo Pinto DRY GAS≈ 181,000 net acres

LIQUIDS RICH 2012e program: >30% of production is liquids

Significant free cash flow

Liquids-rich drilling inventory: ≈2,500 locationsHood

Tarrant

Johnson

Ft. Worth

LIQUIDS-RICH≈443,000 net acres

Liquids rich drilling inventory: 2,500 locations

2012 plans: Drill ≈300 wells

JohnsonErath

Hill

OKLAHOMA

Hill

TEXAS

www.devonenergy.com Slide 22

Artificial Lift TodayRenewed focus at Devon

• Oil and liquid rich resource playsq p y

• Horizontal wellbore configurations

• Increasing volumes of completion fluids

• Tighter margins (especially in older gas fields) requires increase in

operational efficiency


Artificial Lift ChallengesLiquid Rich Environment

Horizontal laterals either toe-up, toe-down, flat, undulated or a

combination of all four drilling scenarios.

Preferred for artificial lift – Toe-up

Worst for artificial lift – Undulated

Longer laterals (7,500’ -10,000’) plus tighter turns

Gas break o t iss es d e to liq id rich environment; operating at or near Gas break out issues due to liquid rich environment; operating at or near

bubble point of the reservoir fluids in some reservoirs

Sand production especially a problem with early use of ESP’s


Artificial LiftMethods to Handle Gas Problems

Use of new down hole gas separators on rod pumped wells instead of “Poor

Boy” gas anchors. Down hole separators are improving pump efficiency and

reducing gas locking issues.

Drilling a sump system when running ESP’s on liquid rich wells with high GOR Drilling a sump system when running ESP s on liquid rich wells with high GOR

ratios. Allowing pumps to run more efficiently and with less down time due to

gas locking.


Artificial LiftSump System for an ESP

Devon Energy Corporation

Surface Csg @ ~500'

Wellbore schematic showing sump system with horizontal liner for frac

Packer set in Intermediate string for frac

5 000' L l

Intermediate Csg with window cut

~5,000' Lateral

Cemented liner

~4,000' TVD


Perf and plug for frac~10‐12 frac stages

Whipstock set in intermediate casing to mill window

Artificial LiftSump System for an ESP

Devon Energy Corporation

Surface Csg @ ~500'

Wellbore schematic showing sump system with horizontal liner an ESP installed

2 7/8" 6.5 # L‐80 8rd Tbg String

~5,000' Lateral

Intermediate Csg with window cut

Cemented linerPerf and plug for frac10 12 f t

~4,000' TVD


~10‐12 frac stagesWhipstock set in intermediate casing removed for ESP installationin sump

ESP assy ‐ motor, pressure gauge package, seal unit, gas separator & pump

Artificial LiftFuture Needs in Liquids Rich Plays

Understanding multiphase flow in long laterals with multiple entry points and

varying pressures.

What is the best way to drill a lateral for producing with artificial lift.

Downhole multiphase pumping capabilities.

Better erosion control when pumping frac sand.

Improve nodal anal sis models for hori ontal wells; better critical velocit Improve nodal analysis models for horizontal wells; better critical velocity

models.


Decision support systems have enabled effective

utilization of Artificial Lift applications

Impact of Decision Support Systems (DSSs) on Field ManagementHow DSSs Accelerate Effective Decision- Potential Impact on Field

Deploy reporting tools that identify well anomalies quicker

How DSSs Accelerate Effective Decisionmaking?

Potential Impact on Field Operations

• Inc Resource Utilization• Improve Environment, Health

and Safety record

DSS A l t

Utilize analytical tools to identify anomalies before they happen

• Reduce lease operating expenses (e.g. hydrate analyses)DSSs Accelerate

Effective Decision-making

y pp

Upgrade analytical capabilities of the field personnel

• Reduce downtime (use critical rates to identify liquid loading

bl t )

analyses)

the field personnel

Enhance collaboration between d i l & i

problems, etc)

• Accelerate production (performance based on potential

production personnel & engineers(p pand not on recent average, proper application of AL)

page 29NYSE: DVN www.devonenergy.com

Example #1: Advanced analytics have enabled Artificial

Lift Selection Process based on well operating conditions

LIQUID LOADING WORKFLOW PROCESS STEPSa

00 4

GLR ( bbl/cf )

0 314 628

c

WASHAKIE

Evaluate performance of well vs. target

Identify & prioritize

a

b00 4

00 4

Well 1

Well 10

Well 100

Well 102

Well 103 Well 105

Well 106

Well 107Well 108

Well 109

Well 11

Well 110

Well 111

Well 112

Well 113

Well 114

Well 116

Well 117

Well 118Well 119Well 12

Well 120

Well 122

Well 123

Well 125

Well 126

Well 127

Well 128

Well 129

Well 13

Well 130

Well 132

Well 133

Well 134Well 135

Well 136

Well 137

Well 138

Well 139

Well 14

Well 140

Well 141

Well 142

Well 145

Well 146

Well 149

Well 15

Well 150 Well 151 Well 152

Well 153

Well 154

Well 156

Well 157

Well 158

Well 159

Well 16

Well 160

Well 161 Well 162

Well 163

Well 164

Well 165

Well 166

Well 167

Well 168

Well 169

Well 17Well 170

Well 171

Well 172

Well 173Well 174

Well 175

Well 177

Well 178

Well 18

Well 180

Well 181

Well 183Well 184

Well 185

Well 186

Well 188

Well 189

Well 19

Well 190

Well 191

Well 192Well 193

Well 194

Well 196

Well 197

Well 199

Well 20

Well 200Well 201

Well 202

Well 203

Well 204

Well 205

Well 206

Well 208

Well 209

Well 21Well 210

Well 211

Well 212

Well 213

Well 214

Well 215

Well 216

Well 217

Well 218

Well 219

Well 22

Well 223

Well 224

Well 225

W ll 227

Well 228

Well 229

Well 23Well 230

Well 231

Well 232

Well 234

Well 235

Well 236Well 238

Well 24Well 25

Well 26

Well 27Well 28

Well 29

Well 3

Well 34

Well 35

Well 36

Well 37

Well 38

Well 39

Well 41Well 42

Well 43

Well 44

Well 45

Well 48

Well 49

Well 5

Well 50

Well 51

Well 52

Well 53

Well 54

Well 55

Well 56

Well 58

Well 59

Well 6

Well 60Well 61

Well 62

Well 63

Well 64

Well 65

Well 66

Well 67Well 68

Well 69

Well 7

Well 70

Well 72

Well 73

Well 74

Well 76

Well 77

Well 78Well 79

Well 8

Well 80

Well 82Well 84

Well 85

Well 86

Well 88

Well 90 Well 91

Well 92

Well 93

Well 94

Well 95

Well 97

Well 98

Well 99

Identify & prioritize underperforming wells

Utilize GLR to recommend initial AL technique

cb

00 4Well 101Well 104

Well 115


Well 137Well 143

Well 144Well 148

Well 176Well 179

Well 182Well 187

Well 195

Well 198Well 2

Well 207

Well 214

Well 220Well 221


Well 233Well 237


Well 33

Well 36Well 4

Well 40

Well 46 Well 47

Well 57

Well 71

Well 72

Well 75

Well 81

Well 83 Well 87Well 89 Well 9

Well 92Well 96

d

initial AL technique

Water cut analysis to fine tune recommendation

d

BENEFITS• Consistent approach based on analytics as opposed to experience• Most optimal method applied for liquid loading

RISKS • Availability of accurate and updated targets


Example #2: Enabled proactive surveillance of “on-target”

wells that are “almost-loading” using critical rate calculations

“ALMOST LOADING” WORKFLOW

WASHAKIE

Review daily gas rate versus critical gas rate

PROCESS STEPS

Review list of wells that are “almost loading”

Utilize GLR/WC analysis from liquid loading workflow to recommend AL technique

BENEFITS• Proactive approach to identify and take action on wells before

they liquid load

RISKS • Critical rate equation based on assumptions might not apply to all wells


Lesson Learned: Success is 80% People and Processes

and the rest is Technology

Key Lessons Learned

Address people and process issues: These aspects pose crucial significance for the successful implementation of Decision Support model and so, consequently should be properly considered during the design and implementation program.

Extensive engagement of the asset: Regular meetings, telephone conversations with communities to understand their demands and achieve their “buy-in” of the concept.

Asset Ownership: Local management owns the process.

Establish benefits framework. Benefits should be tracked and discussed with the relevant stakeholders

Understand impact on support infrastructure: Analyze existing hardware/software/processes for Understand impact on support infrastructure: Analyze existing hardware/software/processes for potential changes.

32

Innovation – The Key to Success

We usually find oil in new places with old ideas. Sometimes, we find y f p foil in an old place with a new idea, but we seldom find much oil in an old place with an old idea.

Several times in the past we have thought that we were running out Several times in the past we have thought that we were running out of oil, when actually we were running out of ideas.

Parke A. DickeySeptember 15, 1958

QUESTIONS?

Documents

Devon Energy Overview - ALRDC Files... · Devon Energy Overview Todd Moehlenbrock, Vice President – Engineering Technology ... DVN Slide 11 (40% Oil & Liquids) Resource By Asset