Shale Play

---

Using Petroleum System and Play Fairway Analysis to Evaluate Sweet Spots in Shale Gas and Shale Oil Jay E. Leonard, Ph.D. Ph.D. Platte River Associates, Inc. Boulder Colorado, USA.

Risk of Resource Plays: “Insiders Sound an Alarm Amid a natural Gas Rush” New York Times, 6/25/11.

“…Oil companies have been placing enormous bets on shale gas and other resource plays. However, resource plays are not without risk…” “…data show that while there are many very active wells, they are often surrounded by vast zones of less-productive wells that in some cases cost more to drill and operate than the gas they produce is worth.” “…companies are also adjusting their strategies to make money by focusing on shale wells that produce lucrative liquids, like propane and butane, in addition to natural gas.”

“Besides the embarrassment for (redacted) of losing money in the Rolls Royce of shale plays, the wider lesson for investors is that, despite the buzz, shale offers no free lunches. Oil isn’t spread uniformly beneath the ground – that’s why companies have to be good at pinpointing it (“Sweet Spots”).” - Wall Street Journal (April 29, 2013) -

Unconventional Play Types • Basin Center Gas • Coalbed Methane • Fractured Shale Gas • Thermally Mature Shale Oil • Shallow Basin Methane / Biogenic Gas • Tight Gas Sands • Gas Hydrates

Five Fundamental Requirements:

• • • •

High Initial Organic Content (> 5%) Appropriate Thermal History Low Expulsion Potential (Primary Migration) Preservation of Organics and Hydrocarbons through Geologic Time • Brittleness Fracking Friendly

Shale Gas Resource Play Scope Play Fairway Approach (presence and effectiveness) Source & Reservoir

2-D Seismic 3-D Seismic Multi-Trace Attributes Fracture Velocity Anisotropy Acoustic Impedance Fracture Modelling

Geophysics

Petrophysics Shale Composition Core Analysis Log Analysis Fracture Analysis Delta log R Methods Imaging Logs Gas-in-Place Calculation

Burial History Thermal History Paleogeography Geochemistry Generation Expulsion Adsorption

Geology

Engineering

Resources & Reserves

Economics Geomechanics, Hydraulic Fracturing Drilling & Completions Production Well Performance Monte Carlo Simulations

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Traditional Resource Play Scope Play Fairway Approach (presence and effectiveness) Source & Reservoir

2-D Seismic 3-D Seismic Multi-Trace Attributes Fracture Velocity Anisotropy Acoustic Impedance Fracture Modelling

Geophysics

Petrophysics Shale Composition Core Analysis Log Analysis Fracture Analysis Delta log R Methods Imaging Logs Gas-in-Place Calculation

Burial History Thermal History Paleogeography Geochemistry Generation Expulsion Adsorption

Geology

Engineering

Resources & Reserves

Economics Geomechanics, Hydraulic Fracturing Drilling & Completions Production Well Performance Monte Carlo Simulations

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Parameters Critical for Source Rock Plays

Barnett Shale

TOC [10]

(Jarvie, 2003)

TR [1]

Ro [2.2]

Tmax [600]

Gas [1000000]

(Curtis, 2002)

Radar Plots Upper Bakken Parshall Well

Radar Plot Settings

Platte River Associates Shale Gas Source/Reservoir Workflow

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Platte River’s Overview Workflow (Patent Pending) TOC Determination Original TOC

Organic Matter Type

Source Basin Mod Model

Maturity

Effective Source Rock?

NPV

Y

Generated Gas, Condensates & Liquids Free Gas Adsorbed Gas

Properties

Reservoir

Porosity

PetroAnalyst

Shale Play Analysis

Maps

Monte Carlo Select Geological Sweet Spots

Portfolio Shale Gas Simulator

NPV Y Effective Reservoir?

Pressure Copyright 2004-2011 Platte River Associates, Inc. All rights reserved

14

Source

Shale Play Analysis

Reservoir

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TOC Determination Source

Organic Matter Type

Original TOC

Effective Source Rock?

Maturity

Shale Play Analysis

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TOC Determination Source

Organic Matter Type

Original TOC

Effective Source Rock?

Maturity

Shale Play Analysis

Properties

Reservoir

Porosity

Effective Reservoir?

Pressure

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TOC Determination Source

Organic Matter Type

Original TOC

Effective Source Rock?

Maturity

Y

Maps

Monte Carlo

Shale Play Analysis

Generated Gas Free Gas Adsorbed Gas

Properties

Reservoir

Porosity

Select Geological Sweet Spots Shale Gas Simulator

Y Effective Reservoir?

Pressure

Copyright 2004-2011. All rights reserved; Platte River Associates, Inc. Confidential. Patent Pending

TOC Determination Source

Organic Matter Type

Original TOC

Effective Source Rock?

Maturity

NPV

Y

Maps

Monte Carlo

Shale Play Analysis

Generated Gas Free Gas Adsorbed Gas

Properties

Reservoir

Porosity

Select Geological Sweet Spots

Portfolio Shale Gas Simulator

NPV Y Effective Reservoir?

Pressure

Copyright 2004-2011. All rights reserved; Platte River Associates, Inc. Confidential. Patent Pending

Unconventional Play Types • Basin Center Gas • Coalbed Methane • Fractured Shale Gas • Thermally Mature Shale Oil • Shallow Basin Methane / Biogenic Gas • Tight Gas Sands • Gas Hydrates

Unconventional Play Types • Basin Center Gas • Coalbed Methane • Fractured Shale Gas • Thermally Mature Shale Oil • Shallow Basin Methane / Biogenic Gas • Tight Gas Sand • Gas Hydrates

Copyright 2004-2012. All rights reserved; Platte River Associates, Inc. Confidential. Patent Pending

USA Shale Gas Potential Resource Estimate Potential Gas Committee (2009): 616 Tcf

The Utica Shale Unconventional Gas Resource Play

A Geologist’s Perspective

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New York State Shale Stratigraphy PERIOD

GROUP

UNIT

Conewango Conneuat

Riceville Chadakoin Undiff Perrysburg - Dunkirk Java Nunda Rhinestreet Middlesex Geneseo Tully Moscow Ludlowville Skaneateles Marcellus Onondaga Oriskany Manlius Rondout Akron Camillus Syracuse Vernon Lockport Rochester Irondequoit Sodus Reynales Thorold Grimsby Whirlpool Queenston Oswego Lorraine Utica

Canadaway

DEVONIAN

UPPER West Falls Sonyea Genesee ?

MIDDLE

Hamilton

Tristates LOWER

Heldergerg

SILURIAN

Salina UPPER Lockport

Clinton LOWER

ORDOVICIAN

Medina

UPPER

MIDDLE

TrentonBlack River

LOWER

Beekmantown

LITH.

THICKNESS

Sh, ss, cgl

700’

Sh, ss

700’

Sh, ss Sh, ss

1100 – 1400

sh

PRODUCTION

Primary Black/Gray Shales Oil, Gas Oil, Gas Gas

Sh, ss Sh, ss

365 – 1250’

Oil, Gas

Sh

0 – 400’

Gas

Sh

0 – 450’

Ls

0 – 50’

Sh

Dunkirk Rhinestreet Geneseo

Gas

Sh Sh Sh

Hamilton/

200 – 600’

Sh

Gas

Ls

30 – 235’

Gas, Oil

Ss

0 – 40’

Gas

Ls Dol Dol

Marcellus

0 – 10’ 0 – 15’

Gas

Sh, gyp Dol, sh, slt

450 – 1850’

Sh Dol Sh

150 – 250’ 125’

Gas Gas

Ls Sh Ls

Gas

Rochester Sodus

75’

Ss Sh, ss

75 – 150’

Gas

Ss

0 – 25’

Gas

Sh Ss

Gas 1100 – 1500’

Lorraine

Sh Sh

900 – 1000’

Trenton

Ls

425 – 625’

Black River Tribes HillChuctanunda

Ls

225 – 550’

Ls

0 – 550’

Gas

Utica

ORDOVICIAN

New York State Ordovician Stratigraphy UPPER

MIDDLE

TrentonBlack River

LOWER

Beekmantown

Queenston Oswego Lorraine Utica

Sh

Sh

900 – 1000’

Trenton

Ls

425 – 625’

Black River Tribes HillChuctanunda

Ls

225 – 550’

Ls

0 – 550’

Ss

Gas 1100 – 1500’

Sh

Jacobi, 2002

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Gas

Ettensohn, 2004

ORDOVICIAN

New York State Ordovician Stratigraphy UPPER

MIDDLE

TrentonBlack River

LOWER

Beekmantown

Queenston Oswego Lorraine Utica

Sh

Sh

900 – 1000’

Trenton

Ls

425 – 625’

Black River Tribes HillChuctanunda

Ls

225 – 550’

Ls

0 – 550’

Ss

Gas 1100 – 1500’

Sh

Jacobi, 2002

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Gas

Ettensohn, 2004

Utica

Trenton

Utica Shale Stratigraphy:

Cross, Gareth E., Fault-Related Mineralization in the Mohawk Valley, Eastern New York State, Master’s Thesis, SUNY at Buffalo. 2004.

Why The Utica Shale? • The Utica is considered the source rock for most of the east’s Cambrian through Silurian reservoirs. • The shale, however, has been described as being “sub-bituminous, because fresh samples can be ignited. • “Preliminary evaluation of the Ordovician shales in the Lowlands of Quebec indicates that there is a good potential for gas production from the fractured Lorraine and Utica groups. • Rich Organic Content: Utica 1.5-3% Eastern NYS, 2-15% (measured not original) • Excellent Gas Quality: 90% to 97% methane (Eastern New York) • Notable shows of gas through the Utica section, Lobdell #1, Chenango Co., the Leslie #1, Delaware Co., Konstantinides #1, Chemung Co., Maxwell #1, Steuben Co., and the Puskarenko #1, Herkimer Co. after John Martin Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Utica Shale: Present Day Maturities (%Ro)

Burned Out Based on Conodont Measurements (Ordovician) OFR-89-488 Wallace, 1989

2.1 0.4 0.9

3.3

OFR-00-496 Weary, 2000

4.5

0.4 0.9

OFR-02-302; Repetski, 2002

2.1

1.5

3.3

0.9 2.7 1.5

4.5 3.9

3.9

Why The Utica Shale? • The Utica is considered the source rock for most of the east’s Cambrian through Silurian reservoirs. • The shale, however, has been described as being “sub-bituminous, and fresh samples can be ignited. • Evaluation of the Ordovician shales in the Lowlands of Quebec indicates that there is a good potential for gas production from the fractured Lorraine and Utica groups. • Rich Organic Content: Utica 1.5-3% Eastern NYS, 2-15% (measured not original) • Excellent Gas Quality: 90% to 97% methane (Eastern New York) • Notable shows of gas through the Utica section, Lobdell #1, Chenango Co., the Leslie #1, Delaware Co., Konstantinides #1, Chemung Co., Maxwell #1, Steuben Co., and the Puskarenko #1, Herkimer Co. Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Konstantinides #1, Chemung County

Utica Shale Gas Shows

Why does this highly mature (Burned Out) Utica Shale have significant gas shows throughout New York?

Summary of Utica Resource Shale Evaluation Source Rock Thickness

Source Rock Lithology

Missing/Eroded Section

Structural History

Free Gas Amount adsorbed

Potential gas adsorbed Thermal History Amount generated

OM amount and Type

Maturity

Petroleum Systems Plot

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New York 3D Model

V.E. ≈ 20

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Utica Shale GDE (460Ma)

Trenton Platform

Carbonate Platform

Basin Slope Basin Floor Turbidite

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Elements of the Utica Shale Analysis • • • •

TOC Thickness Porosity Adsorption

Elements of the Utica Shale Analysis • • • •

TOC Thickness Porosity Adsorption

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Organic-Rich Utica:

Original TOC (%)

Controls of TOC distribution: 1) Location of restricted Foreland Basin

Basement faults Utica “Foreland Basin” outline

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Late Devonian Paleo-Geography

Organic-Rich Utica:

Original TOC (%)

Controls of TOC distribution: 1) Location of restricted Foreland Basin 2) Location of Basement Faults (fault bound isolated “Mini-Basins”)

fault bound isolated anoxic “Mini-Basins” ?

Basement faults Utica “Foreland Basin” outline

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Organic-Rich Utica: High resolution measured TOC pattern

PRA, Inc. Proprietary Data (all others from Jarvie) PRA, Inc. Proprietary Data Well location

5 0 0

6 0 0

7 0 0

8 0 0

9 0 0

10 0 0

11 0 0

0

Model Input

12 0 0

(Tops are from the database)

1 0

0

2

0

0

3

0

0

4

0

0

5

0

0

13 0 0

14 0 0

15 0 0

Lorraine

16 0 0

17 0 0

T

r e

n

t o

n

T re n to n 6

0

0

7

0

0

18 0 0

“Flattened” on Trenton

5 6 0 0 1 .

3

5

1

.

4

0

1

.

4

5

1 .

5

0

4 8 0 0

5 7 0 0 4 9 0 0

5 8 0 0

L o rra in e

5 0 0 0

5 9 0 0

L o rra in e

5 2 0 0

6 10 0

5 3 0 0

6 2 0 0

5 4 0 0

6 3 0 0

L o rra in e

5 10 0

6 0 0 0

L o r ra in e

Utica

5 5 0 0

L o rra in e 5 6 0 0 6 4 0 0

5 7 0 0 6 5 0 0

5 8 0 0

U t ic a

6 6 0 0

U tic a 5 9 0 0 6 7 0 0 6 0 0 0

U t ic a

6 8 0 0 6 10 0 6 9 0 0 6 2 0 0

T re n to n

7 0 0 0

T re n t o n

6 3 0 0

7 10 0

T re n to n

T re n t o n

T r e n t o n

T re n t o n

Trenton

T r e n t o n

6 4 0 0

75 00

76 00

77 00

78 00

79 00

80 00

L o ra in e

8 10 0

4 3 0 0

82 00

4 4 0 0

L o r r a in e

L o rra in e

7 6 0 0

8

5

0

0

4 7 0 0

L o rra in e

7 7 0 0

8

6

0

0

8

7

0

0

85 00

L o r ra in e

4 8 0 0 7 8 0 0

8

8

0

0

8

9

0

0

9

0

0

0

0

0

U t ic a

5 0 0 0 8 0 0 0

5

0

0

0

5 1 0 0

U tic a

U t ic a

89 00

90 00

8 1 0 0 9

U 5

1

t i c

1 0

0

9

2

0

0

9

3

0

0

U t ic a

a

0

0

5 2 0 0

5

2

0

0

5 3 0 0

5

3

0

0

5 4 0 0

9 10 0

8 2 0 0

U tic a

U t ic a 92 00

8 3 0 0

93 00

8 4 0 0

T 5

4

0

0

5

5

0

0

r e

n

t o

9

4

0

0

9

5

0

0

n

T re n t o n

5 5 0 0

T r e n to n

T re n to n

L o rr a in e

U tic a

88 00

7 9 0 0

9

86 00

87 00

4 9 0 0

4

L o rra in e

84 00

7 5 0 0

4 6 0 0

U tic a

L o r r a in e

83 00

4 5 0 0

T re n t o n

8 5 0 0

T r e n to n

5 6 0 0 8 6 0 0

94 00

Tren to n

T re n t o n

95 00

8 7 0 0

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Tre n to n

T re n t o n

T re n t o n

T re n t o n

Utica-Trenton Correlations, Eastern New York

Organic Rich Zone

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Organic-Rich Utica: Measured average TOC (%) PRA, Inc. Proprietary Data Public data Data

Carbonate Platform

Organic-Rich Utica: Original TOC (%) PRA, Inc. Proprietary Data Public data Data

Carbonate Platform

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Elements of the Utica Shale Analysis • • • •

TOC Thickness Porosity Adsorption

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Utica Shale Isopach Map ( ft )

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Organic-Rich Utica: Depositional Thickness (ft) Thickness values

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Elements of the Utica Shale Analysis • • • •

TOC Thickness Porosity Adsorption

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Organic-Rich Utica: Present Day Porosity (%)

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Excess Pressure Determination with the Effective Stress Method Coupled Diagenesis

Organic Porosity in Marcellus Shales

Orange dots are 30 nm in diameters

(Laughrey et al., Weatherford Labrotories, 2011) Copyright 2004-2011. All rights reserved; Platte River Associates, Inc.

Bubble Wrap concept – analog to Overpressure phenomenon At atmosphere pressure (1 atm), bubble wrap is not expanding.

In the unpressurized baggage compartment of an airplane the pores on the bubble wrap expand due to decreased pressure at high altitude. The pressure increases in each pore but is not high enough to burst the wrap.

A single pore (nanometer) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Petroleum Systems Plot

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Fractures – Helping the Source Rock Play Work

Fractures – How and When are they formed? • Three Primary Mechanisms: • Fractures caused by hydrocarbon generation • Fractures caused by tectonic forces • Fractures caused by Halliburton

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Hydrocarbon Generation Fractures

Lower Bakken shale displaying microfracturing generated by oil expulsion

1 centimeter

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Tectonic/Structural Fractures

Moab area, Utah Comb Monocline area, Utah

Flexure Fractures

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Trenton Fm. Brittleness Map with depositional environment

NY

PA

OH

Pennsylvania Embayment

Lexington Platform After Wickstrom et al. (1992) and Cornell (2003). Image modified from: http://www.mcz.harvard.edu/Departments/InvertPaleo/Trenton/Intro/GeologyPage/ Geologic%20Setting/paleogeogsetting.htm#easternlaurentia

Elements of the Utica Shale Analysis • • • •

TOC Thickness Porosity Adsorption

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Irving Langmuir (1881—1957)

Gas Storage Potential of the Utica and Marcellus

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Langmuir Adsorption Isotherm Amount of Methane adsorbed is a function of: -

TOC Temperature Pressure etc.

θ ads (P ,T ,TOC ) = θ max

bP 1 + bP

Measured Predicted

T = 70 ºF TOC = 2.16%

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Methane Langmuir Adsorption bP 1 + bP

Adsorption increases with: increasing pressure due to - burial - generation pressure (oil, gas, oil to gas cracking) - ice shield development

80

0 (ºC)

20 (ºC) 40 (ºC)

70

Adsorption potential (scf/ton)

θ ads (P ,T ,TOC ) = θ max

Adsoprtion Potential vs Temperature & Pressure 60 (ºC) 80 (ºC) 100 (ºC) 120 (ºC)

60

140 (ºC) 160 (ºC) 50

Declining Temperature

180 (ºC) 200 (ºC)

40

220 (ºC)

30

240 (ºC) 260 (ºC) 280 (ºC) 300 (ºC)

20

10

0 0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000 11000 12000 13000 14000

Pore Pressure (PSI)

decreasing temperature due to

increasing TOC due to - higher original organic matter content

180

160

Adsorption Potentail (scf/ton)

- uplift / erosion - decreasing heat flow or thermal gradient - glaciations

Adsorption Potential vs TOC & Pressure

5.0 (%)

140

4.5 (%) 4.0 (%)

120

3.5 (%) 100

3.0 (%)

Increasing TOC

80

2.5 (%) 2.0 (%)

60

1.5 (%) 40

1.0 (%) 20

0.5 (%)

0 0

1000

2000

3000

4000

5000

6000

7000

8000

Presssure (PSI)

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9000

10000 11000 12000 13000 14000

Organic-Rich Utica: Present Day Temperature (ºF)

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Organic-Rich Utica: Present Day Pore Pressure (PSI)

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Organic-Rich Utica: Depositional Thickness (ft) Thickness values

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Organic-Rich Utica: Original TOC (%) PRA, Inc. Proprietary Data Public data Data

TOCinit

TOCmeas = 1 − (TR ⋅ ∆C )

Carbonate Platform

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Organic-Rich Utica:

Methane Adsorption Potential (STP scf/ton )%

Present Day Methane Adsorption Potential (STP scf/ton )

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Adsorption Potential ( scf/ton )

Adsorption Potential vs. Temperature & Pressure History (schematic)

Source Rock Deposition

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Increasing Pressure & Temperature

Adsorption Potential ( scf/ton )

Max. Adsoprtion Potential

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Pore Pressure ( PSI )

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Fracturing Generation Pressure

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Fracturing Generation Pressure

Pressure Bleeding

Pore Pressure ( PSI )

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Gas Generation Oil-Gas Cracking

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic)

Adsorption Potential ( scf/ton )

Subsidence Ends

Maximum Burial (max. temperature)

Pore Pressure ( PSI )

Adsorption Potential ( scf/ton )

Adsorption Potential vs. Temperature & Pressure History (schematic)

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential ( scf/ton )

Adsorption Potential vs. Temperature & Pressure History (schematic)

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential ( scf/ton )

Adsorption Potential vs. Temperature & Pressure History (schematic)

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI )

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Fracturing ChangingTectonic Stress

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Fracturing Tectonic Stress

Pressure Bleeding Fast -> Isothermal?

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI )

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Glaciation increasing pressure & declining temperature

Subsidence Ice Sheet Loading

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Deglaciation decreasing pressure & inclining temperature

Present Day Adsorption Potential

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Adsorption Potential vs. Temperature & Pressure History (schematic) Subsidence Adsorption Potential ( scf/ton )

Increasing Pressure & Temperature

Deglaciation decreasing pressure & inclining temperature

Present Day Adsorption Potential

Glaciation increasing pressure & declining temperature

Fracturing

Fracturing Pressure Bleeding

Pressure Bleeding

Maximum Burial

Uplift Decreasing Pressure & Temperature

Pore Pressure ( PSI ) Copyright 2004-2012. All rights reserved; Platte River Associates, Inc.

Ice Shield Effect Ice density=1.0 - Ice w/ 4% rock content

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The Utica Shale Production Sweet Spot Identification

Gas Generated (MMCF/mi2)

Moderate risk – yellow > 30,000 MMCF/mi2 4,058 mi2

Low risk – green > 50,000 MMCF/mi2 5,746 mi2

Gas Adsorbed (MMCF/mi2)

Moderate risk – yellow > 8,000 MMCF/mi2 1,351 mi2

Low risk – green > 10,000 MMCF/mi2 5,495 mi2

Porosity (%)

Moderate risk – yellow > 1.0 % 1,998 mi2

Low risk – green > 1.5 % 25,489 mi2

Free Gas (MMCF/mi2)

Low risk – green > 10 MMCF/mi2 22,785 mi2

Depth (feet)

Moderate risk – yellow > 2,500 feet 1,390 mi2

Low risk – green > 3,000 feet 19,620 mi2

Rollup

Moderate risk – yellow 2,238 mi2 29.5 TCF

Low risk – green 2,784 mi2 44.8 TCF

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The Utica Shale Sweet Spot Identification

An Engineer’s Perspective

SGPM

Solve: gas mass balance water mass balance Gas deliverability water deliverability

INPUT PROPERTIES: • • • • • •

reservoir fluid rock fluid adsorption well PVT

Newton’s Method

OUTPUT PROPERTIES: • • • •

rates cumulative production pressure saturation

New York’s Utica “Sweet Spot” Study Area

Parameters for 6 vertical well models • • • •

Reservoir Properties Depth: 4000-7200 (ft) Reservoir Temperature: 100-150 (F) Reservoir Pressure: 1800-3200 (psi)

• • • • • • • •

Key Model Parameters Bulk Volume: 2.3E+06 to 4.9E+06 (ft^3) Permeability: 0.004 (mD) Desorption Pressure: 1000-1800 (psi) Langmuir Volume: 76 scf/ton Fracture half-length: 100 (ft) Fracture porosity: 0.05 Initial Water Saturation: 0.12

Parameters for 6 horizontal well • • •

Well Design 4000 ft lateral 10 stage frack

• • • •

Reservoir Properties Depth: 4000-7200 (ft) Reservoir Temperature: 100-150 (F) Reservoir Pressure: 1800-3200 (psi)

• • • • • • • •

Key Model Parameters Bulk Volume: 1.2E+08 to 2.5E+08 (ft^3) Permeability: 0.004 mD Desorption Pressure: 1000-1800 (psi) Langmuir Volume: 76 scf/ton Fracture porosity: 0.05 Fracture half-length: 100 (ft) Initial Water Saturation: 0.12

76

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Bakken Shale – Organic Richness Vertical Distribution Total Organic Material Vertical Variation in Core Plugs Clarion Res 1-24 Slater 24-161N-91W

7850

50% by volume

7860

Immature Bakken Shales are partially kerogen supported

Organic Mat. vol % Ave ~40%

7870

7880

Depth

7890

7900

Mineral matrix Organic matrix

TOC wt % Ave ~20%

7910

7920

From Palciauskas, 1991 7930

7940

Immature Upper Bakken

7950 0

10

20

30

40

50

60

Toc Weight % Organic Matter Vol %

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Beaver Meadow 1

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Beaver Meadow 1 – Vertical Well Cumulative Gas (Bcf): 0.066

Gas rate (MMCF/day): .37

Fracture Porosity: 0.05 Estimated bulk volume: 8.20E+06 ft^3 Desorption Pressure: 1200 psi Permeability: 0.004 mD

Beaver Meadow 1 – Horizontal Well Cumulative Gas (Bcf): 3.12

Gas rate (MMCF/day): 6.8

Estimated bulk volume: 6.26E+08 ft^3 Desorption Pressure: 1200 psi Permeability: 0.004 mD Fracture Half Length: 300 ft.

Clough K&O 1

Clough K&O 1 – Vertical Well Cumulative Gas (Bcf): 0.041

Gas rate (MMCF/day): .280

Estimated bulk volume: 4.62E+06 ft^3 Desorption Pressure: 1200 psi Permeability: 0.004 mD

Clough K&O 1 – Horizontal Well Cumulative Gas (Bcf): 1.98

Gas rate (MMCF/day): 4.61

Estimated bulk volume: 3.53E+08 ft^3 Desorption Pressure: 1200 psi Permeability: 0.004 mD Fracture Half Length: 300 ft.

Vertical and Horizontal Well Comparison Normalized (unitless)

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New York’s Utica “Sweet Spot” Study Area

MODE

100 ft.

MAX

100 ft.

MIN

100 ft.

200 Total Feet

MIN

100 ft.

Shattered Bulk Volume 4,000 X 200 X 200 = 1.6 E8 100 ft.

MODE

100 ft.

MAX

100 ft. 100 ft. 100 ft. 100 ft. 100 ft.

200 Total Feet 400 Total Feet

MODE MAX

100 ft.

MAX MODE MIN

Shattered Bulk Volume 4,000 X 200 X 200 = 1.6 E8

MIN

Shattered Bulk Volume 4,000 X 200 X 400 = 3.2 E8

100 ft. 100 ft. 100 ft.

MODE

100 ft.

MAX

100 ft.

100 ft.

MIN

Shattered Bulk Volume 4,000 X 200 X 200 = 1.6 E8

200 Total Feet 400 Total Feet 600 Total Feet

MAX MODE

Shattered Bulk Volume 4,000 X 200 X 400 = 3.2 E8

MIN

Shattered Bulk Volume 4,000 X 200 X 600 = 6.4 E8

Estimated Bulk Volume

Fracture Permeability

Reservoir Pressure and Temperature

Desorption Pressure

Fracture Porosity Langmuir Volume Gas Flow Rate

SGPM Calculation

Cumulative Gas

Monte Carlo Sampled, Input Probability Distribution Calculated Probability Distribution

Gas Production Calculation

Monte Carlo Production Simulation

Gas Production

Gas Flow Rate

Cumulative

Gas

Estimated Bulk Volume

Water Formation

Volume Factor

Fracture Permeability Reservoir Reservoir Pressure and and Pressure Temperature Temperature

Langmuir Volume

Desorption Pressure

Gas Flow Rate

Production Calculation for Exploration

Reservoir Thickness

Production Calculation

Monte Carlo Production Simulation

Gas Formation Volume Factor

Average Gas Flow Rate Pressure Decline Curve/Rate

Gas In-Place Volume

NPV

Gas Recoverable Reserves Free/Adsorbed Gas Recovery Factor

Cumulative

Gas

Monte Carlo Sampled, Input Probability Distribution

NPV: Net Present Value Calculated Probability Distribution

Spearman's rank correlation coefficient

Cumulative Gas - Clough

p10 – Cumulative Gas (Bcf)

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p90 – Cumulative Gas (Bcf)

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p50 – Cumulative Gas (Bcf)

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Unconventional Play Types • Basin Center Gas • Coalbed Methane • Fractured Shale Gas • Thermally Mature Shale Oil • Shallow Basin Methane / Biogenic Gas • Tight Gas Sands • Gas Hydrates

Uncertainty Element Proxies Risk Element Source Potential

Conventional Proxy

Unconventional Proxy

TOC, HI, *UEP, analogues, thickness, TOC, HI, *UGP, analogues, thickness, expelled volumes expelled volumes *Ultimate Expellable Potential

*Ultimate Generative Potential

Migration Pathway

Distribution of fluids from known source rocks, distribution of carrier beds, seal facies, expulsion timing v. trap timing

Usually not required due to short migration distances, if any

Reservoir Storage

Porosity, thickness, Net:Gross, analogues

Porosity, thickness, adsorption, analogues

Reservoir Effectiveness

Permeability, Recovery Factor, HC 'Fracability', brittleness, permeability, saturation, analogues, pore analogues, pore pressure, fluid viscosity pressure, PVT behavior Mapping of trap edges, analogues, Not required if a continuous resource number of required sealing elements

Trap Closure

Column Capacity

Mercury injection data, analogues, shale gouge ratios, column height

Mercury injection data, analogues, shale gouge ratios, column height; if relevant

Thank You

Risked Gas In-Place The risked gas in-place estimate is derived by first estimating the amount of ‘gas inplace’ resource for a prospective area within the basin, and then de-rating that gas inplace by factors that, in the consultant’s expert judgment, account for the current level of knowledge of the resource and the capability of the technology to eventually tap into the resource. The resulting estimate is referred to as the risked gas in-place. 1. Conduct a preliminary review of the basin and select the shale gas formations to be assessed. 2. Determine the areal extent of the shale gas formations within the basin and estimate its overall thickness, in addition to other parameters. 3. Determine the ‘prospective area’ deemed likely to be suitable for development based on a number of criteria and application of expert judgment. 4. Estimate the gas in-place as a combination of ‘free gas’9 and ‘adsorbed gas’10 that is contained within the prospective area. 5. Establish and apply a composite ‘success factor’ made up of two parts. The first part is a ‘play success probability factor’ which takes into account the results from current shale gas activity as an indicator of how much is known or unknown about the shale formation. The second part is a ‘prospective area success factor’, which takes into account a set of factors (e.g., geologic complexity and lack of access) that could limit portions of the ‘prospective area’ from development.