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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
Recommended