Evaluation and Modelingof Alaska North Slope

Gas Hydrate Resource Potential

Alaska Gas Hydrate Planning WorkshopAnchorage, Alaska

August 17-18, 2005

Robert Hunter

U.S. Department of Energy

Presentation OutlinePresentation Outline

Introduction / Collaboration

• Gas Hydrate Resource

• Resource Characterization

• Production Technology

• Reservoir/Development Models

• Conclusions

U.S. Department of Energy

UNIVERSITIES

GOVERNMENT

INDUSTRY3D Seismic& Well Data,Infrastructure

ResearchInnovation

UnconventionalResource

Determination

NationalLabs

U.S. Department of Energy

Collaborative Research TeamCollaborative Research Team

Alaska Gas

Gas HydrateProject Manager

Robert Hunter

USGS LeadGas Hydrates

Timothy Collett

UAF PIEngineering Shirish Patil

UA PI Geoscience

Robert Casavant

USGSGeophysics

David TaylorUSGS

Geophysics Warren Agena Co-PI

GeoscienceMary Poulton

Co-PIGeophysicsRoy Johnson

Pete McGrail (PNNL)Tao Zhu (UAF)CO2 Injection

George MoridisLBNL

Reservoir Model

GOVERNMENT INDUSTRY UNIVERSITIES

Co-PIPetrophysics

Charles Glass

UA ConsultantGeoscienceKen Mallon

ParticipatingScientist

S. Khataniar

Co-PIAbhijit Dandekar

ScienceSupport

Godwin Chukwu

Reservoir ModelingDavid Ogbe

EconomicsDoug Reynolds

Collaborative Research TeamCollaborative Research Team

Arun Wagh (ANL)Ceramicrete Cement

Technical Advisor Scott Digert

U.S. Department of Energy

Reservoir Model Scott Wilson

USGS ConsultantGeophysics

Tanya Inks (IS)

National Labs

Brent Sheets (AETDL)UAF-PNNL Projects

USGSGeophysics Myung Lee

Operations Planning Steve Hancock

Phase/Year

Project Timing & PhasesProject Timing & Phases

2001

2002

2004

III

Project ProposalDOE-Industry Alignment

2003

2005

2006

I

II

Drilling/Production RE/PE Studies

Wells of Opportunity – Acquire Data

Reservoir and Development ModelingValidate Regional Prize, DetermineAlignment, Plan/Acquire Data

Characterize Reservoir/FluidCalculate In-Place Resource

U.S. Department of Energy

2007 Possible Pilot Development Testing?

Apply/Test Concepts/Technology, Characterize & Calculate Resource

pre

Presentation OutlinePresentation Outline

Introduction / Collaboration

Gas Hydrate Resource

• Resource Characterization

• Production Technology

• Reservoir/Development Models

• Conclusions

U.S. Department of Energy

Gas Hydrate in U.S.Gas Hydrate in U.S.

ALASKA ONSHORE

GULF OFMEXICO

Petroleum SystemInfrastructureTechnology

Miles

0 5 10 15 20 25

ANWR

Coastal

Plain

(1002 Area)

Canning R

iver

Sagavanirktok River

Colvi

lle R

iver

LJL (April, 1997)

Badami

Operated by BPXA

Operated by ConocoPhillips

Operated by ExxonBPXA (O) 100%Milne Point

Pt. Thomson

Greater Prudhoe Bay

AlpineConocoPhillips (O) 78%Anadarko 22% Endicott

BPXA (O) 68%Exxon Mobil 21%Unocal 11%

Greater KuparukConocoPhillips (O) 55%BPXA 39%Unocal 5%

Exxon Mobil 37%ConocoPhillips 37%BPXA (O) 26%

NorthstarBPXA (O) 98%Murphy 2%

NPRA

Miles

0 5 10 15 20 25

25 Mi/40 km

Location Map

Alaska North Slope OperatorsAlaska North Slope Operators

North Slope Gas Resource 35 TCF

PBU Production = 8 BCF/Day Reinjected Reservoir Energy

Coastal Plain

(1002 Area)

Gas Hydrate In-Place, ANS Basin (USGS) 590 TCFGas Hydrate In-Place, ANS Infrastructure area (USGS) 100 TCFGas Hydrate In-Place, Eileen Trend 33-44 TCF Gas Hydrate/Gas In-Place Milne Point ~ 617/90 BCF (mean)

ANS Infrastructure & Gas HydrateANS Infrastructure & Gas Hydrate

Miles

0 5 10 15 20 25

TAPS

Northstar

NPRA

ANWR

Coastal Plain

(1002 Area)

LJL (April, 1997)

Pt. Thomson

Badami

Colvil

le Rive

r

DevelopmentsDiscoveries

AlpineEndicott

25 Mi/40 km

Location Map

Tarn Gas HydrateEileen Gas/Hydrate

Eileen

Tarn

Kuparuk

Milne Pt.

Prudhoe Bay

N

60 TCF?

>33 TCF

Presentation OutlinePresentation Outline

Introduction / Collaboration

Gas Hydrate Resource

Resource Characterization

• Production Technology

• Reservoir/Development Models

• Conclusions

U.S. Department of Energy

US Bureau of Land Management, US Geological Survey, State of Alaska Division of Geological & Geophysical Surveys

Phase-I. Assess existing geologic, geophysical, and engineering data to characterize the resource potential of the Eileen and Tarn gas-hydrate/free-gas accumulations (FY 03-05). BPXA – USDOE project synergy.

Phase-II. Assess existing geologic, geophysical, and engineering data to characterize the resource potential of the undiscovered gas hydrate accumulations in NPRA, ANWR, and the State lands between the Canning and Colville Rivers (FY 05-06).

Phase-III. Assess the economically recoverable resource potential of gas hydrates and associated free-gas accumulations in northern Alaska (FY 07).

ANS Research Program CollaborationANS Research Program Collaboration

100 km

Gas Hydrate Stability ZoneGas Hydrate Stability ZoneAlaska North SlopeAlaska North Slope

Tarn and EileenGas Hydrate Trends

Petroleum System also Required: Gas Source, Migration, Reservoir, Trap, Seal

Gas Hydrate Core

Gas hydratestability zone

Free-gas &oil- bearing

Ice-bearingpermafrost

Northwest Eileen St. #2— type log

4 MCF/d, 93% CH4 Gas hydratestability zone

Free-gas, oil,or water-bearing

Ice-bearingpermafrostBIBPF

BIBPF

S_36

S_34

S_33

S_31

S_30

S_29

M-Eocene Shale

S_35

Saga

vani

rkto

kFm

.

Gas Hydrate Core Gas Hydrate Test

Eileen Trend Type LogEileen Trend Type Log

Composite of A-F Hydrates

Collett et al 1-2004

Milne Point Gas Hydrate AccumulationMilne Point Gas Hydrate Accumulation

Milne Pt 3D Survey

TARN

EILEEN

Free Gas-prone

Structural ComplexityStructural Complexity

Regional subcrop map across central Barrow arch(Wicks, Frantz, Casavant 1991)

AOI located along major rift margin discontinuity

Northern tip of major transcurrent FZ that segments foreland basin and fold-thrust belt to south (Casavant, 2001)

Basement blocks at variety of scales are differentially uplifted, rotated, translated indicating that arch is faulted rather than just a jog

Long-lived depocenter

Hagbo, 2003

3

Seismic structure (mkr 34)• ~USGS “C” pay unit

Hagbo, ‘03

graben

3 km

brittle-ductile

12

PDZnorth

“East Basin”MPU (schematic)

15

46

2

Idealized pull-apart basin attributes from analog modeling

1. Inactive borderland structures2. Oblique-reverse fault3. Terraced sidewall fault zone4. Cross-basin fault zone5. Negative flower structure6. Relay ramp7. PDZ in-line graben/push-ups

3

7

Transtensional basin => fault complexity

Hagbo, 2003

WSAK 25

~ projection of WSAK-25

bend in section

W E

SidewallShear zone-multiple

reactivation

“East Basin”

AT

Net/grossincreases

En echelongrabens

Seismic Modeling and VelocitiesSeismic Modeling and Velocities

Velocity Pull-up Velocity Push-down

Seismic Amplitude AssessmentSeismic Amplitude Assessment

3-way Fault-boundedTrap, Gas Hydrate-bearing Reservoir

Mt. Elbert Gas Hydrate ProspectMt. Elbert Gas Hydrate ProspectSeismic AmplitudeSeismic Amplitude

Top Staines Tongue Contactagainst Base Gas Hydrate

FREE GAS?GAS HYDRATE?

Gas Hydrate Prospect, Seismic AmplitudeGas Hydrate Prospect, Seismic Amplitude

Gas Hydrate Prospects, USGS C HorizonGas Hydrate Prospects, USGS C Horizon

Wells with “C” Hydrate, 1993 Study (AAPG), T. Collett

20’

8’

55’

45’

Crystal Ball ReportSimulation started on 8/30/04 at 12:02:55Simulation stopped on 8/30/04 at 12:04:37

Forecast: G9 Cell: G9

Summary:Display Range is from 54.3 to 145.3 BcfEntire Range is from 50.3 to 168.2 BcfAfter 10,000 Trials, the Std. Error of the Mean is 0.2

Statistics: ValueTrials 10000Mean 94.9Median 93.3Mode ---Standard Deviation 18.4Variance 338.7Skewness 0.40Kurtosis 2.88Coeff. of Variability 0.19Range Minimum 50.3Range Maximum 168.2Range Width 117.9Mean Std. Error 0.18

Forecast: G9

0

50

100

150

200

250

54.7 72.9 91.1 109.4 127.6

Bcf

Freq

uenc

y

Assumptions

Assumption: Elbert C Cell: G2

Normal distribution with parameters:Mean 3,000,403,160.32Standard Dev. 300,040,316.03

Selected range is from 2,550,342,686.27 to 3,450,463,634.370.00000.00500.01000.0150

2,55

4,84

3,2

91.0

2

2,73

4,86

7,4

80.6

3

2,91

4,89

1,6

70.2

5

3,09

4,91

5,8

59.8

7

3,27

4,94

0,0

49.4

9

BULK ROCKVOLUME

Assumption: G3 Cell: G3

Triangular distribution with parameters:Minimum 34%Likeliest 38%Maximum 40%

Selected range is from 34% to 40%0.00000.0050

0.01000.01500.02000.0250

34% 35% 37% 38% 39%

POROSITYAssumption: G4 Cell: G4

Triangular distribution with parameters:Minimum 70%Likeliest 80%Maximum 95%

Selected range is from 70% to 95%0.0000

0.0050

0.01000.0150

0.0200

0.0250

70% 75% 80% 85% 90%

NET-TO-GROSS

Assumption: G5 Cell: G5

Triangular distribution with parameters:Minimum 40.0%Likeliest 59.7%Maximum 90.0%

Selected range is from 40.0% to 90.0%0.0000

0.0050

0.01000.0150

0.0200

0.0250

40.3% 50.3% 60.3% 70.3% 80.3%

SATURATION

Gas Hydrate Prospect Uncertainty AnalysesGas Hydrate Prospect Uncertainty Analyses

Antero C Bierstadt D Bierstadt E Blanca C Crestone C Elbert C Elbert DGrays Peak

BGRV (cu ft) 2350045580 1119622596 1232193097 740796681 6349463797 3000403160 1761367545 203815727Porosity 38% 38% 38% 38% 38% 38% 38% 38%Net-to-Gross 80% 80% 80% 80% 80% 80% 80% 80%Gas Saturation 66.1% 49.8% 66.9% 55.1% 49.8% 59.7% 52.6% 47.2%1/Bg 164 164 164 164 164 164 164 164

Volume in Placecu ft) 77.4 27.8 41.1 20.4 157.6 89.3 46.2 4.8

MPU HYDRATE PROSPECTS VOLUMETRICSMPU HYDRATE PROSPECTS VOLUMETRICS

Maroon Peak A Mt Princeton D Pikes Peak B Red Cloud B Sneffels D

Uncompaghre Peak D

7 927428988.1 1291844038 397708421.7 585518227.8 1516746825 390458860.9% 38% 38% 38% 38% 38% 38%% 80% 80% 80% 80% 80% 80%% 81.2% 53.2% 68.8% 58.1% 57.6% 49.3%4 164 164 164 164 164 164

8 37.5 34.3 13.6 17.0 43.6 9.6

A Volumes (Bcf) 37.5B Volumes (Bcf) 35.4C Volumes (Bcf) 344.7D Volumes (Bcf) 161.4E Volumes (Bcf) 41.1

Volume 620.2

14 “Intra-Hydrate”Prospects

620 BCF Median Estimated Gas in Place

MPU Location within Eileen TrendMPU Location within Eileen Trend

Miles

0 5 10 15 20 25

TAPS

Northstar

NPRA

ANWR

Coastal Plain

(1002 Area)

LJL (April, 1997)

Pt. Thomson

Badami

Colvil

le Rive

r

DevelopmentsDiscoveries

AlpineEndicott

25 Mi/40 km

Location Map

Tarn Gas HydrateEileen Gas/Hydrate

Eileen

Tarn

Kuparuk

Milne Pt.

Prudhoe Bay

N

33 TCF?

MPU Associated Free Gas VOLUMETRICSMPU Associated Free Gas VOLUMETRICSLong's Peak

MiddleMt Yale Upper

Kit Carson Upper

Maroon Peak Middle

Mt Shavano Middle

Mt Holy Cross Middle

Mt Holy Cross Upper

Area (acres) 796 400 576 380 255 1012 391Gross Thickness (ft) 25 25 25 25 25 25 25Porosity 36% 36% 36% 36% 36% 36% 36%Net-to-Gross 80% 80% 80% 80% 80% 80% 80%Gas Saturation 70.0% 70.0% 70.0% 70.0% 70.0% 70.0% 70.0%1/Bg 108 108 108 108 108 108 108

Volume in PlaceGas (billion cu ft) 18.9 9.5 13.7 9.0 6.0 24.0 9.3

Upper Volumes (Bcf) 32.4Middle Volumes (Bcf) 57.9

Total Hydrate Volume 90.3

7 Prospects Totaling 90.3 BCF Median Estimated Gas In Place

Based on these prospect analyses and proximity to infrastructure, locations to acquire data would be chosen in collaboration with the resource owner

We have developed a workflow that can be used for gas hydrate prospecting in other areas of the North Slope

Presentation OutlinePresentation Outline

Introduction / Collaboration

Gas Hydrate Resource

Resource Characterization

Production Technology

• Reservoir/Development Models

• Conclusions

U.S. Department of Energy

Productivity/Development Challenges Productivity/Development Challenges Gas Hydrate Production MethodsGas Hydrate Production Methods

Dissociated

PRESSURE

Free-Gas

Gas Out

Gas Hydrate

Hydrate

Reservoir

Imperm. Rock

Endothermic Heat of Gas DissociationTemperature Recovery Lag Time Hydrate Self-Preservation

Gas Out

Imperm. Rock

Impermeable Rock

Gas Hydrate

Dissociated Hydrate

Hot Brine or

Gas

Large energy inHeat Host Rock In-situ combustion?In-situ Electromag?

Methanol, Brine, or

CO2

Gas Out

Imperm. Rock

Impermeable Rock

Dissociated Hydrate

Gas Hydrate

ModifiedAfter Collett, 2000

Methanol High costPNNL Lab Tests CO2

Not Field-TestedPotassium Formate?

TEMPERATURE CHEMICALWater Out?

(Movable Water?)

Aquifer Water?

Proof-of-Principle CH4 → CO2

ProofProof--ofof--Principle Principle CH4 CH4 →→ CO2CO2

• Liquid- CO2 Emulsion Best Method• Temperature Reading Immediately

Spiked from -2.5°C to 8°C • Only Methane Gas Output• Lab bench ------ vs... Field Trial

• Thermodynamically Favorable• Offsetting Dissociation Enthalpy:

CO2 Hydrate Formation Heat ~20% > CH4 hydrate dissociation

• Sediment Mechanical Stabilization

Theory: Inject CO2 to Recover CH4 from Gas Hydrate

Results: CH4 from Gas Hydrate by Injecting CO2

Productivity/Development Challenges Productivity/Development Challenges Gas Hydrate Production MethodsGas Hydrate Production Methods

Presentation OutlinePresentation Outline

U.S. Department of Energy

Introduction / Collaboration

Gas Hydrate Resource

Resource Characterization

Production Technology

Reservoir/Development Models

• Conclusions

Reservoir Modeling Historical PerspectiveReservoir Modeling Historical Perspective

Positive By-Productof a Normal Practice

Build Lab Modelto Test Concept

Build Initial Computer Models

Field Test With Specific Objectives

Tune Computer ModelsWith Field Results

Identify Targets for Implementation

• Adapted Industry-Standard Reservoir Models to Gas Hydrate Phase-behavior

• Used CMG-STARS and special inputs• Enabled Well/Field-scale modeling

• Developed Type-Well Cases/Ranges

• Studied Pressure Response Variables• Evaluated Coalbed Methane Analog • Expanded to Full-Field Development

Reservoir ModelingReservoir Modeling

~ Free Gas

Gas Hydrate

175 Meter Horizontal Well 175 Meter Horizontal Well 3 3 ½”½” TubingTubing

CMG STARS Reservoir Model ResultsCMG STARS Reservoir Model ResultsGas Production & Gas Hydrate Dissociation Gas Production & Gas Hydrate Dissociation

5 miles3 miles

~ Free Gas

Gas Hydrate

201 x 340 x 2 cells = 136,680 total cells201 x 340 x 2 cells = 136,680 total cells82.5 foot grid spacing82.5 foot grid spacing

5 miles3 miles

CMG STARS Reservoir Model ResultsCMG STARS Reservoir Model ResultsGas Hydrate Dissociation after 15 yearsGas Hydrate Dissociation after 15 years

Reservoir Model: DepressurizationReservoir Model: Depressurization

Significant Production Increase (~2X) due toFree Gas Dissociation from Gas HydrateSignificant Uncertainties Remain

0

5,000

10,000

15,000

20,000

25,000

30,000

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

0.0E+00

1.0E+10

2.0E+10

3.0E+10

4.0E+10

5.0E+10

6.0E+10Gas Rate : Base Description

Gas Rate : No Hydrates

Cumulative Gas : Base Description

Cumulative Gas : No Hydrates

Gas

Rat

e (m

scfp

d)

Cum

ulat

ive

Gas

(scf

)

Typical Production Profiles

OGIP

Production Profile ComparisonProduction Profile Comparison

INCREMENTAL GAS

• 40% initial Sw• Well Placement

in Hydrate zone• Initial Sw > Swirr

IntraIntra--Hydrate Production ScenariosHydrate Production Scenarios

60% Shyd, 40 % Sw includes 20 % Swirr

80% Shyd, 20 % Swirr

IntraIntra--Hydrate Production ScenariosHydrate Production Scenarios

< Gas Hydrate, > Water> Productivity

> Gas Hydrate, No Mobile Water< Productivity

A

A/B/C/D/E

B/C/D/E

A/B/C/D

C/D/E

C/D/EE

E

B/C/D

C/D

C/D D/E

Base PermafrostTruncation

Base Gas Hydrate

Truncation

Zone GIP(TCF)

Risked GIP

(TCF)ABCDE

Total

18 69 911 86 66 4

50 33

North Slope Hydrate Forecasts Type Well Gas Production Forecasts

0

500

1000

1500

2000

2500

0 10 20 30 40 50 60 70 80 90

Years from Start-up

Gas

Rat

e (m

scfp

d)

160 Acre High Sw640 Acre High Sw640 Acre Low Sw

North Slope Hydrate ForecastsType Well Cumulative Production Forecasts

-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

0 10 20 30 40 50 60 70 80 90

Years from Start-up

Cum

ulat

ive

Gas

(msc

f)

160 Acre High Sw640 Acre High Sw640 Acre Low Sw

North Slope Hydrate Forecasts Type Well Water Production Forecasts

0

100

200

300

400

500

600

700

800

0 10 20 30 40 50 60 70 80 90

Years from Start-up

Wat

er R

ate

(bpd

)

160 Acre High Sw640 Acre High Sw640 Acre Low Sw

Reference Case High Upside CaseNorth Slope Hydrate Forecasts

Type Well Gas Production ForecastsIncluding Upside Type Wells

0

5000

10000

15000

20000

25000

0 10 20 30 40 50 60 70 80 90

Years from Start-up

Gas

Rat

e (m

scfp

d)

160 Acre High Sw640 Acre High Sw640 Acre Low SwUpside 640 Acre Low SwUpside 640 Acre High Sw

North Slope Hydrate ForecastsType Well Cumulative Production Forecasts

Including Upside Type Wells

-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

0 10 20 30 40 50 60 70 80 90

Years from Start-upC

umul

ativ

e G

as (m

scf) 160 Acre High Sw

640 Acre High Sw640 Acre Low SwUpside 640 Acre Low SwUpside 640 Acre High Sw

North Slope Hydrate Forecasts Type Well Water Production Forecasts

Including Upside Type Wells

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

0 10 20 30 40 50 60 70 80 90

Years from Start-up

Wat

er R

ate

(bpd

) 160 Acre High Sw640 Acre High Sw640 Acre Low SwUpside 640 Acre Low SwUpside 640 Acre High Sw

Type Wells

Coal Bed Methane Analog?Coal Bed Methane Analog?

• Predicted to follow historical patterns• Initial positive results expanded to full-field

Stage 1: Initial Pilot Testing and Data Acquisition

Stage 2: Multi-well Pilot Testing and Calibration

Stage 3: Limited Initial Development

Stage 4: Full-Field Development

Stage 5: Resource Harvesting and Optimization

Stage 6: Manage and Expand Resource

Stage 7: New Technology / Infill Drilling

Development ModelingDevelopment Modeling

Stage 1: Single Well Pilot TestingStage 1: Single Well Pilot Testing

Stage 2: MultiStage 2: Multi--well testing/calibrationwell testing/calibration

• Well locations schematic-only• Multi-well 160 Acre Pilot

Stage 3: Limited Initial DevelopmentStage 3: Limited Initial Development

• Well locations schematic-only

• Fully Dependent upon successful Stage 1-2

• Conceptually Similar to WSak 1J pilot in KRU viscous oil

• Additional area tests• First Major Capex• First Reserve Booking

Stage 4: FullStage 4: Full--field developmentfield development

• Well locations schematic-only

• Latter stage development

• Major CapexRequired

• Filters applied to reduce well count to ~148 at 640 Ac. in C/D sands > 0’

• Infilling as-needed

Stage 5: Resource HarvestingStage 5: Resource Harvesting

• Well locations schematic-only

• Latter stage development

• 640 to 320 Acre Spacing

• Infilling to tighter spacing

• Major CapexRequired

• Optimization• Possible new

pad extensions

Stage 6: Manage/Expand ResourceStage 6: Manage/Expand Resource

• Well locations schematic-only

• Very Late-stage development

• 640 to 320 Acre Spacing

• Infilling to tighter spacing and extension

• Major Capex Required• Optimization• Possible multi-laterals• Possible new pad

extensions• Resource on-decline• New Technology?

Stage 7: New Technology/InfillingStage 7: New Technology/Infilling

• Well locations schematic-only

• Latest stage conceptual full-field development

• 160 Acre spacing• Major Capex Required• Optimization• Improved technology?

Production trends predicted using the type wells and development timing. Four cases:

1. Downside case: Poor Pilot test, additional testing and ultimate project economic failure, technical resource evaluation success.

1-4 wells, 0 TCF Recovered

2. Reference case: Encouraging pilot results and Stage 2 (18 well) pilot development transition into large scale development.

172 wells, 2.5-9.6 TCF

3. Upside case: Good pilot and Stage 2 results transition into 320 acre development with heat or chemical assisted production.

283 wells, 3.6-11.8 TCF

4. Extreme upside case: Outstanding pilot/Stage 2 confirms resource; development moves forward rapidly on 640 acre spacing.

141 wells, 8.8-9.3 TCFPotential case analog in the lower-48 Coal Bed Methane (CBM)

FieldwideFieldwide Production ForecastsProduction Forecasts

Cumulative gas & water

Reference CaseReference Case

STAGE 1 2 43

1 2 430

2,000,000,000

4,000,000,000

6,000,000,000

8,000,000,000

10,000,000,000

12,000,000,000

1/14/2004 9/22/2017 6/1/2031 2/7/2045 10/17/2058 6/25/2072 3/4/2086 11/11/2099 7/21/21130

500000000

1000000000

1500000000

2000000000

2500000000

3000000000

Reference Case Cumulative Gas Production Reference Case Cumulative Water Production

Cumulative gas & waterMCF Gas Bbls Water

Upside CaseUpside Case

0

2,000,000,000

4,000,000,000

6,000,000,000

8,000,000,000

10,000,000,000

12,000,000,000

14,000,000,000

1/14/2004 9/22/2017 6/1/2031 2/7/2045 10/17/2058 6/25/2072 3/4/2086 11/11/2099 7/21/21130

500000000

1000000000

1500000000

2000000000

2500000000

3000000000

3500000000

4000000000

Upside Case Cumulative Gas Production Upside Case Cumulative Water Production

Cumulative gas & waterMCF Gas Bbls Water

Extreme Upside CaseExtreme Upside Case

0

1,000,000,000

2,000,000,000

3,000,000,000

4,000,000,000

5,000,000,000

6,000,000,000

7,000,000,000

8,000,000,000

9,000,000,000

10,000,000,000

1/14/2004 9/22/2017 6/1/2031 2/7/2045 10/17/2058 6/25/2072 3/4/2086 11/11/2099 7/21/2113

Extreme upside Case Cumulative Gas Production Extreme Upside Case Cumulative Water Production

Cumulative gas & waterMCF Gas Bbls Water

• Dissociation & gas production character/rate• Associated water production rate• Endothermic effects of production• Initial and dissociating permeabilities• Gas hydrate saturations• Production technologies

• Prospect delineation of seismic-prospects• Production testing (short & long-term)• Thermal enhancement understanding• Sand control, Artificial Lift, In-situ combustion?

Production UncertaintiesProduction Uncertainties

Uncertainty MitigationsUncertainty Mitigations

Presentation OutlinePresentation Outline

U.S. Department of Energy

Introduction / Collaboration

Gas Hydrate Resource

Resource Characterization

Production Technology

Reservoir/Development Models

Conclusions

• ANS – Gas Hydrate Petroleum System• Complex Shallow Structure & Stratigraphy• Multiple High-graded MPU Prospects Revealed: 620 BCF• Regional Development Scenarios Under Evaluation

• Significant uncertainties remain • Regional Resource In-Place may be >33 TCF Eileen Trend• Resource Potential Remains Uncertain – 0-12 TCF possible• Direct Detection Geophysical Methods Require Delineation• Additional Data Acquisition Could Calibrate Resource Potential• Type Well Production Rates Modeled at 0.4-2 MMSCF/d • Peak Field-wide Forecast Models up to >350 MMSCF/d• Modeled Production Character Long with Flat Declines• Potentially High Associated Water Volumes

• Technical Project Results Helping to Solve Issues• Industry & Government to make more Informed Decisions

Interim ConclusionsInterim Conclusions