Presentation OutlinePresentation Outline

• Project Overview

• Resource Characterization

• Stratigraphic Test Results

Reservoir Simulation

• Production Testing

• Conclusions / Future Plans

Schematic Reservoir ModelSchematic Reservoir ModelDevelopment Scenario OptionsDevelopment Scenario Options

3 miles2 m

iles

95ft

Methane Hydrate Free Gas

WaterCalculate Recovery FactorsEvaluate/Contrast Single/Multiple Methods

Simple Model: Simple Model: Depressurization Under Hydrate Depressurization Under Hydrate

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

OGIPINCREMENTAL GAS

UPPER STAINES TONGUE HYDRATE ZONE

UPPER STAINES FREE GAS ZONE

Geologic Description Geologic Description Simulation ModelSimulation Model

~ 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

Moving front hydrate dissociationMoving front hydrate dissociation

Reactions at the hydrate/gas interface cause local cooling.Reactions at the hydrate/gas interface cause local cooling.

High net pressure is left behind the reaction frontHigh net pressure is left behind the reaction front

Well Placement: In Hydrate zone where Well Placement: In Hydrate zone where initial initial SSww greater than or equal to irreducible greater than or equal to irreducible SSww

• 40 % init Sw

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

ZoneGIP

(TCF)

Risked GIP

(TCF)ABCDE

Total

18 69 911 86 66 4

50 33

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

Stage 2: Multi-Well Pilot Testing

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

Stage 3: Limited Initial DevelopmentStage 3: Limited Initial Development

Similar in scope to WSak 1E/1J pilot in

KRU viscous oil

Filters applied to reduce wellcount to ~148 at 640 Acre Spacing in C & D sands > 0’ thickness

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

Stage 5: Resource HarvestingStage 5: Resource Harvesting

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

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

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 WellsType Wells

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

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

500,000,000

1,000,000,000

1,500,000,000

2,000,000,000

2,500,000,000

3,000,000,000

Reference Case Cumulative Gas Production reference Case Cumulative Water Production

Cumulative gas & water

MCF Gas Bbls Water

Reference CaseReference Case

STAGE 1 2 43

1 2 43

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

Upside CaseUpside Case

MCF Gas Bbls Water

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 7/21/21130

500,000,000

1,000,000,000

1,500,000,000

2,000,000,000

2,500,000,000

3,000,000,000

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

Extreme Upside CaseExtreme Upside Case

MCF Gas Bbls Water

Mount Elbert MDT Mount Elbert MDT Key ResultsKey Results

• Confirmation of gas release via depressurization

• Clear indication that depressurization alone may not be sufficient in select (T) settings

• Confirmation of mobile water phase • Sgh = 65%; 25% = Swirr• Sgh = 75%; 10% = Swirr

• Determination of intrinsic K• 0.12 – 0.17 mD

• Reformation kinetics may be important

• Detailed reservoir heterogeneity may control productivity

Fluids ProducedFluids Produced

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0

Test Time, hours

Cum

ulat

ive

Gas

Pro

duct

ion,

sm

3

0

0.01

0.02

0.03

0.04

0.05

Cum

ulat

ive

Wat

er, s

m3

Measured-cumulative gas

Measured-cumulative water

Smoothed! Gas and Liquid Production

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 5000 10000 15000 20000 25000 30000 35000 40000

Elapsed Seconds

BLP

D in

-situ

0

100

200

300

400

500

600

700

800

900

QG

(scf

/d)

QlblPD BH

QGSCFPD

MDT Testing MDT Testing Pulse pressures through the Pulse pressures through the system : measure responsessystem : measure responses

6”6”

9”7”

2”8” 19

”

Packer inflatesto full contactwith borehole

IntakeScreen

How much gas is How much gas is 1.0 1.0 cfcf downhole?downhole?

The red annular area The red annular area to the left is 1.5 to the left is 1.5 cfcf

38”Tool

Zero

Gridding that recognizes Gridding that recognizes the wellbore annulusthe wellbore annulus

MDT

Well

2149.5 ft

1 m

10 m

Fluid Production Point

2152.5 ft

0.06 m

0.111 m

MDT Testing MDT Testing Annular Space is critical Annular Space is critical in this low rate casein this low rate case

MDT Results Reservoir ModelingMDT Results Reservoir ModelingInternational Code Comparison GroupInternational Code Comparison Group

A

B D

E

A: Stomp-HYD (M. White – PNNL)

B: STARS (S. Wilson – RyderScott)

C: MH-21 (M. Kurihara – JOE)

D: STARS (M. Pooladi-Darvish – Fekete)

E: Tough+/HYDRATE (G. Moridis – LBNL)

0

2

4

6

8

10

12

0.000 2.000 4.000 6.000 8.000 10.000 12.000

Time (hour)

Pressure (M

Pa)

-3.000

-1.000

1.000

3.000

5.000

Tem

perature (C)

Pressure (mesured)

Pressure (calc : Case A)

Temperature(mesured)

Temperature (calc : Case A)

C

0

250

500

750

1000

1250

1500

1750

2000

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0

Test Time, hours

FBH

P, p

si

30.0

31.0

32.0

33.0

34.0

35.0

36.0

37.0

38.0

39.0

40.0

FBH

T, o F

FBHP actualsimpressFBHT actualSimTemp

NW Eileen St-2

PBU L-106

W Kuparuk St 1

W Kuparuk 7-11-12

W Sak 24

KRU 1H-6

KRU 1C-8

KRU 1D-8

Beechy St-1

Mount Elbert 01

PBU V-107

1

2

3

4

DOWNDIP

Site Comparisons Reservoir ModelingSite Comparisons Reservoir Modeling

50-year Production Scenarios:1. Mt. Elbert-like formation

2.5-3.0°C, Sh = 65%, P ~ 6.7 MPa

2. PBU L-Pad5.0-6.5°C, Sh = 75%, P ~ 7.3-7.7 MPa, 2 zones

3. Down-dip formation10-12°C, Sh = 75%, P ~ 8-9 MPa,2 zones, near base of GHSZ

Simulation of Alternative LocationsSimulation of Alternative Locations

J Pad Pressure and Temperature

Mt. Elbert Location

Simulation of Alternative LocationsSimulation of Alternative Locations

Area 2 (Warmer Location)

Mt. Elbert

Area 3 (Warm Location)

Warmest LocationAt Hydrate/Gas Interface

CC--Unit Heterogeneity Affects Unit Heterogeneity Affects Simulation Saturation ProfilesSimulation Saturation Profiles

0

1000

2000

3000

4000

5000

6000

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000time, days

Gas

rate

, m3 /d

ay

homogenousheterogenous

Effect of permeability & porosity Effect of permeability & porosity heterogeneity on predicted production ratesheterogeneity on predicted production rates

Affects of Reservoir HeterogeneityAffects of Reservoir HeterogeneityDetail time ScaleDetail time Scale

50-layer log data modelProblem 7a base case

Typical Flow Rates in Commercial wellsTypical Flow Rates in Commercial wellsthis well also takes a long time to show its full potentialthis well also takes a long time to show its full potential

C2 MDT rate (0.3 mscf/d)C2 MDT rate (0.3 mscf/d)

An example of publishedsimulation study rates

(8 mmscf/d average)

An example of publishedsimulation study rates

(8 mmscf/d average)

Mallik Flow Test * (~70 to 140 mscf/d)

Mallik Flow Test * (~70 to 140 mscf/d)

* Yamamoto and Dallimore (2008)Dallimore et al. (2008)

Note long clean-up timesNote long clean-up times

Presentation OutlinePresentation Outline

• Project Overview

• Resource Characterization

• Stratigraphic Test Results

• Reservoir Simulation

Production Testing

• Conclusions / Future Plans

Coal Bed Methane Analog?Coal Bed Methane Analog?

Year84 86 88 90 92 94 96 98

A LT U D A

20000

2

4

6

8

10

12

14

16

COALBED METHANE WELLS IN U.S.COALBED METHANE WELLS IN U.S.

4538

583364286785

725878388094

9029

2992

284 384 513 477 6571445

10,927

13,986

COALBED METHANE PRODUCTION IN U.S.COALBED METHANE PRODUCTION IN U.S.

Year85 87 89 91 93 95 97 99

0

200

400

600

800

1,000

1,200

1,400

A L T U D AEnergy InformationAdministration (1992,1995,1999, 2002)

1,600

2001

1,800

539

752851

956 10031090

11941252

348

10 17 24 40 91196

1379

1562

PROVED COALBED METHANE RESERVES AS PROVED COALBED METHANE RESERVES AS OF 2001OF 2001

1,000

2,000

3,000

4,000

5,000

0

6,000

7,000

A LT U DA

Energy InformationAdministrat ion (1992,1995,1999, 2002)

New Mexico

EXPLANATION

Colorado

Alabama

Other

1989

1991

1993

1995

1997

1999

2001

2003

2005

Virg in ia

Utah

Alabama

Wyoming

New Mexic o

Colorado

010002000

3000

4000

5000

6000

7000

Virginia

Utah

Alabama

Wyoming

New Mexico

Colorado

US CBM Reserves

Source : EIA 10/2008

BCF Reserves

PROVED COALBED METHANE PROVED COALBED METHANE RESERVES AS OF 2006RESERVES AS OF 2006

xxxxxx

THE FIRST SUCCESSFUL SHALE GAS PLAYTHE FIRST SUCCESSFUL SHALE GAS PLAY

Technical Resource

Design and run short term test with Rig

Short term test promising stimulation

options

Implement medium term test

Proved Reserves

Rig off / design medium term

test

Quantify Resource

Long-term tests

Shut-down

Predicted short depressurization test

volumes are measurable+

-

+

+

+

-

+

+

- +

Short

Long

Time Scale

Medium

-

Gas Hydrate Flow Test DecisionGas Hydrate Flow Test DecisionScenario & Contingency PlanningScenario & Contingency Planning

Evaluate Stimulation OptionsSalt Water flushMatrix Acid jobCavitationFracPropped Frac

MDT

Potential issues1.Solids create production problems:

1.Install Gravel pack2.Produce sand 3.(Pump) Frac sand back into fm 4.Cavitation (CBM Model) 5.Resin coat 6.Some combination of the above 7.Other

2.Wellbore freezes off:1.Inject methanol down capillary2.Circulate hot gas 3.Add electrical well heating:

Radiant or Induction 4.Add downhole combustion

3.Production volumes very small but increasing slowly:

1.Evaluate stimulation options 2.Soak with destabilizing agents3.Hydraulic Fracture with conventional or unconventional fluids 4.Evaluate sidetrack option

Drill and Test Vertical Well Drill and Test Vertical Well

Failure path 1: Evaluate Stimulation Failure path 1: Evaluate Stimulation Options in Vertical Well Options in Vertical Well

1. Evaluate secondary methods as a huff-n-puff (inject-soak-produce) to measure stimulation/extraction benefits

1.Hot and cold, liquid and gas, slow and fast, matrix and fracture pressure 1.Water/Steam 2.Methane 3.CO24.PBU gas = 12% CO25.Inhibitors, solvents, biological

2.Continue until not successful

Design with expectation of severe sand production including dedicated circulation strings, sand capable pumps from toe and heel. Take advantage of significant experience in both West Sakand Steam Assisted Gravity Drainage (SAGD) operations.

1.Progress through prior technology sequence using the horizontal well.

Failure Path 2: Sidetrack Existing Well Failure Path 2: Sidetrack Existing Well Drill Horizontal SectionDrill Horizontal Section

Failure path 3: Drill Second Failure path 3: Drill Second Vertical Pilot LocationVertical Pilot Location

• Drill second pilot location and attempt to confirm or overcome negative results• Follow pilot study procedures proven successful in CBM, tight gas and Shale gas