EnerCom's London Oil & Gas Conference

16 June 2011

London, England

Overview of Shale Plays

Danny D. Simmons

Barnett Shale

Historical Gas Production

Gas

Production

Rig

Count

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Jan 00 Jan 01 Jan 02 Jan 03 Jan 04 Jan 05 Jan 06 Jan 07 Jan 08 Jan 09 Jan 10 Jan 11

Daily G

as P

rodu

cti

on

(B

CF

D)

0

50

100

150

200

250

300

Rig

Cou

nt

Barnett Shale

Chronology of Completion Techniques

Older vertical well

with older gel-based

fracture stimulation

Recent horizontal well with

newer light-sand based

fracture stimulation

Cum 1,362 MMCF

Newer vertical well with

newer light-sand based

fracture stimulation

Cum 857 MMCF

Refrac treatment of older vertical

well with newer light-sand based

fracture stimulation

Cum 692 MMCF

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Jan-95 Jan-96 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05

Ga

s R

ate

(M

MC

FD

)

Barnett Shale Type Curve

Northeast Wise County

100

1,000

10,000

100,000

0 12 24 36 48 60 72 84 96 108 120

Time (Months)

Gro

ss G

as (

MC

F/M

on

th)

0

20

40

60

80

100

120

Well C

ou

nt

Barnett Shale

Variation in Well Performance

• Wide range of performance trends for

wells in close proximity

• EURs range from 0.3 Bcf to 3.6 Bcf

– Average EUR is 1.5 Bcf

• There may not be a 'typical' well

Barnett Shale

Northeast Wise County

Barnett Shale

Northeast Wise County

100

1,000

10,000

100,000

0 12 24 36 48 60 72 84 96 108 120

Time (Months)

Gro

ss G

as (

MC

F/M

on

th)

0

20

40

60

80

100

120

We

ll Co

un

t

Average of 107 wells

Projection of Average Production

Well Count

Year P25 Mean P50 P75 Avg. Lateral Length (Feet)

2002 and Earlier 1,814 1,533 1,363 743 1,297

2003 2,729 1,999 1,553 847 1,414

2004 2,775 2,172 1,812 1,005 1,885

2005 3,074 2,238 1,853 1,054 2,391

2006 3,011 2,217 1,968 1,004 2,921

2007 3,591 2,704 2,452 1,462 2,930

Gas EUR (MMCF)

Barnett Shale

Variation in Well PerformanceYearly Gas Ultimate Distribution

Barnett Shale Tier 1 Area

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

0 10 20 30 40 50 60 70 80 90 100

Greater Than (Percent)

Ga

s E

sti

ma

ted

Ult

ima

te R

ec

ov

ery

(M

MC

F)

2002 and Earlier 2003 2004 2005 2006 2007

`

Completion Improvements

Lateral Length

No. of Fracs

Type of Proppant

Shale Gas

Comparison between Plays

Play

Age

Depth

(feet)

Thickness

(Net feet)

Pressure

(psi)

TOC

(%)

Porosity

Net (%)

BCFE/D

(Jan 2011)

Barnett

Mississippian

6,500-8,500 100-300 3,500-

6,000

2.0-5.0 3-5 5.3

Fayetteville

Mississippian

4,000-7,000 100-200 2,000-

4,500

2.0-5.0 3-5 2.5

Haynesville

Jurassic

10,500-

13,500

100-200 8,500-

12,000

0.5-3.0 5-9 5.0

Marcellus

Devonian

4,000-8,500 50-200 2,000-

6,000

3.0-7.0 3-10 2.3

Eagle Ford

Cretaceous

6,000-13,000 100-200 5,500-

10,500

2.0-7.0 3-9 2.2

Time

Rate

50 mbo

400 mbo

200 mbo

• How much oil and/or gas are wells going to make, and

• Can my Company make $ drilling wells?

Simplistic Goals of Reservoir Engineer

OOIP

OGIP

Temperature

TOC

Porosity vs. TOC

Porosity

Pressure

Fluid Analysis

Free Gas vs.

Adsorbed Gas

Natural

Fracture

Hydraulic

FractureRo

Permeability -

Natural

Permeability -

Induced

Well SpacingRecovery Factor

Vertical vs. LateralRecovery per Incr.

Lateral Foot

Prices

Costs

GR GRRT D,N

10’High Quality Net

60’ Quality Net

General Principles

Higher silt content

(Rt and Rhob)

Higher organic

content

(GR)

Hydrocarbon

ProfileHigher silt content

(Rt and

Rhob)

430' Gross

250' Net < 2.5 g/cc

OGIP

+/- 175 BCF/Sq Mi

More is Better…

Storage Capacity (In-Place)

Flow Capacity (Perm)

Reservoir Energy (Rec. Factor)

Shale Gas Storage SystemS

ch

lum

berg

er P

rivate

SPE Mid-Continent Section – May 15, 2003

Gas Storage & Production Mechanisms

Naturally Fractured, Organic-Bearing Shale Reservoirs

Desorption From

Internal Surfaces

Flow Through

the Matrix

Flow in the Natural

Fracture Network

Organic

CarbonMatrix

Natural

Fractures

Hydraulic

Fracture

Density & SpacingPorosity

Permeability

Net Thickness

Reservoir Pressure

TOC - Total Organic

Carbon

120 - 140 Bcf/mi2

Adsorbed Gas

associated with TOC

Sch

lum

berg

er P

rivate

SPE Mid-Continent Section – May 15, 2003

Gas Storage & Production Mechanisms

Naturally Fractured, Organic-Bearing Shale Reservoirs

Desorption From

Internal Surfaces

Flow Through

the Matrix

Flow in the Natural

Fracture Network

Organic

CarbonMatrix

Natural

Fractures

Hydraulic

Fracture

Density & SpacingPorosity

Permeability

Net Thickness

Reservoir Pressure

TOC - Total Organic

Carbon

120 - 140 Bcf/mi2

Standard porosity associated with space

between grains or shale particlesSubmicroscopic porosity associated with

conversion of TOC to hydrocarbons

Nanopores

TOC

Reed et al., Texas BEG; Presented by Bob Loucks, AAPG

San Antonio 2008; Submitted for publication 2008

Free Gas

associated with matrix porosity

TOC @ 3% by weight equates to 6% volume

(reading on the standard porosity log)

Organic Material-Porosity Relationship

Log Porosity (Volume %) = TOC (wt%) + Real Porosity (Volume %)

This is the single most significant difference between Shale Free

gas analysis and conventional reservoir Free Gas analysis

TOC

Nanopores

Natural Fracture Density

Increased density

• increases porosity,

• increases cross-sectional area,

• decreases distance fluid has to flow

Gas Reservoir Permeability vs Recovery Factor

0.0000001

0.0000010

0.0000100

0.0001000

0.0010000

0.0100000

0.1000000

1.0000000

10.0000000

100.0000000

1,000.0000000

10,000.0000000

0% 5% 10% 15% 20% 25% 30% 35%

Porosity

Re

serv

oir

Pe

rme

ab

ilit

y (

md

)

Unconventional

Tight

Recovery Factors

30 to 50%

Conventional

Recovery Factors

50 to 95%

Shale

Recovery Factors

5 to 30%

Gas Reservoir Permeability vs. Recovery Factor

Maximizing Drainage Area

dx

dy

Contributing Volumes Less than 100% Gross Rock Volume

Increasing Frac

Stages

Increasing Frac

Density

Downspacing

Horizontal Drilling Schematic

Shale Gas

Evaluation Considerations

• Shale plays may require considerable initial capital expenditures to allow commercial access and determine economic feasibility.

• Geoscience costs tend to be very large early in shale plays:

Seismic in areas without recent petroleum exploration activity

Coring and laboratory analysis

• Learning curve – earliest wells in new play may deliver poor results as drilling and completion technology is perfected.

• General shale play economics improve over time due to: More effective drilling and completion techniques

Better understanding of reservoir and identification of "sweet spots"

• Long-term investment Shale gas plays have very large in-place volumes and very large drilling

location inventories that may take decades to realize.

• Two-day seminar (no registration cost)

• Dallas – May 2012

• London – June 2012

• Dates and locations will be announced in early 2012

• Pre-register on-line at www.netherlandsewell.com

Netherland, Sewell & Associates, Inc.

Because there is a difference.

info@nsai-petro.com

www.netherlandsewell.com

DallasThanksgiving Tower

1601 Elm Street

Suite 4500

Dallas, Texas 75201

214-969-5401

Houston 4 Houston Center

1221 Lamar

Suite 1200

Houston, Texas 77010

713-654-4950