Horizontal Fracturing in Shale Plays

Matt McKeon

Shortening the learning curve

• Historically: a trial-and-error processy p• Data acquisition• USA analog fields can speed up

evaluation and development

Quantify Construct Complete Analyze

Gas Rate SimGas RateOil RateOil rate Sim

2

Recent plays: fracture stimulations are evolving

WaterFracs 8-10 Stages

80 100 BPM

Hybrid/Conv 12-15 Stages

80-100 BPM 1.5 MM lbs prop 100 Mesh, 40/70 1 ppg Max

40-60 BPM 3-4 MM lbs prop

(total) 30/60 20/40

7 MM Gal 40,000 HHP 350-450’/Stage

30/60, 20/40 3-4 ppg 4 MM Gal 25,000 HHP 250-300’/Stage

2008 2009 2010

3

Eagle Ford

Even Barnett stimulation is still changing

Barnett Shale Completion Roadmap Barnett Shale Completion RoadmapBarnett Shale Completion Roadmap

80

90

600

700

Barnett Shale Completion Roadmap

30000

35000

4000

4500

50

60

70

PM

400

500

20000

25000

ge 2500

3000

3500

30

40Avg

. BP

200

300

10000

15000

bbl/s

tag

1500

2000

ge

0

10

20

0

100

0

5000

0

500

1000

span

ft.

BPMTreatment span sk

s/st

ag bbl/stagesks/stage

4

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

year1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

Shale Gas Development Process WorkflowData Acquisitionq

55

Shale parameters to enhance commercial production

Gas content : > 100 scf/ton Thermal maturity (Ro) : 0.7 to 2.5+ range; 1.2 typical Permeability : greater than 100 nanodarcies Porosity : > 4% Pressure : above normal TOC : > 2% Water saturation : < 45% Well bounded & thick zone : > 100 ft Well bounded & thick zone : > 100 ft Moderate clay content : < 40% Well bounded : i.e. good frac barriers Brittle shale (fracability) : i.e. low Poisson’s & high YM Natural fractures : moderate presence

6

Shale Prospect Woodford Barnett Haynesville Marcellus Eagleford Bakken

Porosity (%) 5.5 1-8% ~1.5 – 6 (Avg. ~3.8) 8 - 15% 3 – 8% 3- 15% 2 - 12 %

TVD (ft) 4,100 – 4,300 6,000 – 14,000 5,400 – 9,500 10,500 – 14,000 4,500 - 8,500 5,000 - 13,000 8,000 - 11,000

Thickness (ft) 53 100 - 220 100 - 500 60 - 350 50 - 300 40-500 6-15ft & 80-145 ft

BHT (° F) 160 150-225 150 280-380º F 100-150 150 - 350 190 - 240

TOC (%) 3.95 3-9% 4-8% 2-5% 3-10% 0.5-9% Upper-11%-40%Lower=8%-21%

Press Grad (psi/ft) 0.48 .45-.68 0.52 0.85 - 0.93 0.4 - 0.7 0.4 – 0.85 0.5 - 0.6

Frac Grad (psi/ft) 0.7 .7-.9 ~0.6 – 0.75 >0.90 0.9 – 1.2 .88-1.1 0.70 – 0.85

Avg Perm (μd) 0.1 0.05-0.4 0.05 – 0.4 <0.005 0.2 - 2 400-1200 20 - 500

Sw (%) 27 33% <35 no free water <25 10-30 25 - 60

Lithology (%) Silica rich Silica- Chert 30-60% Silica rich 35-50 v/v Shale is soft (ductile)Calcite rich-in areassilica rich (in areas)

organic rich

Variable formation properties

Illite clay-dominatedQuartz/Plagioclase/

F ld

~3-5% carbon content

High Illite-dominate clays

L k lik “ k

Silty, sandy, dolomite grading to laminated shaly interval. Some

natural fractures.Below is Sanish

High clay mineral fraction

Feldspar Carbonates

Siderite/Pyrite

Looks like “poker chips”

High in Calcites

Below is Sanish

YM (x106 psi) 3.48 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2 - 4Middle=4-6

PR (%) 0.206 0.15-0.25 0.13-0.25 0.23 – 0.27 0.19 – 0.23 0.20-0.27 Upper/Lower=-0.25-0.280.28

Middle= 0.2 – 0.25

Quartz, wt % 54 25-54 40-60 25-52 10 - 40 1—30 15 - 70

Plagioclase feldspar, wt %

10 7-13 2-5 8-17 0 – 10 0-17 1 - 3

C l it t % 3 7 7 20 5 30 13 44 5 20 25 95 15 65Calcite, wt % 3.7 7-20 5-30 13-44 5 – 20 25-95 15 - 65

Smectite,wt % 2-8 1-5 - < 2 0-23 2 - 6

Illite, wt % 11.9 17-46 5-25 12-20 25 - 60 1-50 1 - 13

Kaolinite wt % 8 0 0 - < 2 0-14 0 - 2

Chlorite, wt % 11.9 1 0 4-7 0 – 10 0-7 1 - 3

R (M t it f 1 23 0 75 1 45 0 6 1 6 1 1 2 0 8 3 0 0 75 2 16 0 45 0 60Ro (Maturity of Shale)

1.23 0.75 – 1.45 0.6-1.6 1 – 1.2 0.8 – 3.0+ 0.75 – 2.16 0.45 – 0.60

Analog Analysis

U.S. shale play: choose stimulation

Barnett Woodford Haynesville Eagle Ford MarcellusFrac System Waterfrac (WF) WF /Linear Gel WF, Hybrid, &

X-Linked Hybrid WF and Hybrid

TVD 5,400-9,500 ft. 6,000-14,000 ft. 10,500-14,000 5,000-13,000 ft. 4,500-8,500 ft.

Lateral Length 4,000 ft. 4,000 ft. 4,500 ft. 4,000 ft. 3,000-5,000 ft.

Stages 4 8 6 12 10 15 12 15 10 14Stages 4-8 6-12 10 - 15 12-15 10-14

Fluid Volume 5.0 MM (8 stg) 6.5 MM (10 stg) 5.0 MM (10 stg) 4.0 MM (12 stg) 5.0 MM (12 stg)

Proppant Vol. 3.5 MM lbs. 4.5 MM lbs 2.5 MM lbs 3.5 MM lbs 5.5 MM lbs

Completion Type Cemented Csg. Cemented Csg. Cemented Csg. Cemented Csg. Cemented Csg.

(1)P&P (2)BASS

(1) P&P(2) BASS

(1) P&P(2) BASS

(1) P&P(2) BASS

(1) P&P(2) BASS

(3)Hydrajet (3) Hydrajet (3) Hydrajet (3) Hydrajet (3) Hydrajet

Span/Stage 400 ft. 400 ft. 300 ft. 250-400 ft. 150-400 ft.

Clusters/Length 42 4 ft

42 4 ft

4-61 2 ft

4-81 2 ft

3-52 4 ft2-4 ft. 2-4 ft. 1-2 ft. 1-2 ft. 2-4 ft.

Analog Analysis

Shale Analysis Log Where would you perforate? Where would you perforate?

What is the TOC and gas content?

Will it frac and what is the relativeReservoirPropertiesLithology Brittle

or Ductile?

Kerogen Content Natural

Fractures?

Unconfined Compressive

Strength

Mineralology

Will it frac and what is the relative fracture width and barriers?

What is the shale volumetric gas in place?Fractures?in place?

What is the shale porosity and permeability?

Where is the organic rich shale?

Where are the zones of highest kerogen content

ShaleType

Frac“Ease”

TOCHydrocarbon

Content

kerogen content

9

SPE 115258

Shale fracturing simulation

• Designed for complex g pfracturing

• Couple available data with microseismic to optimize fluid system

d f d iand frac design • Recalibrate model based

on post job analyses andon post job analyses and regional variations

OBJECTIVEMaximize stimulated reservoir volume (SRV)( )

11

Shale fracture characteristics

To create complexity you must have:1. Pre-existing natural fissures

2. Low differential horizontal stresses (net pressure > σm)

Ductile                                                                                                             Brittle

( p m)3. Brittleness

•Woodford• Bakken

• Barnett• Haynesville• Eagleford

• Tight Gas Sands

12

a e•Marcellus

Eagleford

Shale Completion Strategy: Based on Formation Brittleness & Liquid Production

Brittleness Fluid SystemFracture

GeometryFracture Width Closure Profile

SPE 115258

Brittleness Fluid System Geometry Closure Profile70% Slick Water

60% Slick Water

50% Hybridy

40% Hybrid

30% X-Linked

20% X-Linked20% X Linked

10% X-Linked

Proppant Fluid Proppant LiquidBrittleness

Proppant Concentration

FluidVolume

Proppant Volume

Liquid Production

70% Low High Low Low

60%

50%

40%

30%

20%

13

20%

10% High Low High High

Shale fluid decisions

Shale Type Frac Type Fluid Type & Prop ppg

Brittle & low clay

•Complex network•No embedment

•Water 0-2% KCL•0.1-2 ppg

Brittle & high clay

•Complex network•Some embedment

•Water 2-7% KCL•Linear gel. •0.1- 3 ppg

Ductile & low clay

•Less complex•Moderate embedment

•Water 0-2% KCL•Linear gel. X-Link Tail•0 5 5 ppg•0.5 – 5 ppg

Ductile & high clay

•Bi-Wing•High embedment

•Linear Gel 2-7% KCL•X-Link

1414

High embedment•0.5-10 ppg

Lateral design, stage intervals & well spacing

• Lateral• Drilled in direction on minimum horizontal stress for transverse fracturing• Drilled in direction on minimum horizontal stress for transverse fracturing• Greater than 90 degree deviation is common practice• Stay in best portion of the reservoir while drilling• Longer laterals yield more production – to a point → cost considerations

• Stage intervalsg• Number of intervals varies by shale play – most 300 to 400 ft• Most often, shorter intervals increase SRV and production → more cost• Couple with perforation interval distribution for optimum SRV from frac

• Well Spacing

15

• Well Spacing

Perforation clusters

• Typically evenly spaced along stage interval – good rock or bad• Number of clusters varies by shale play, less perm & complexity → closer

• Number of perfs affect limited entry diversion• The more clusters placed the less contribute to production

16

The more clusters placed, the less contribute to production• Placement in better rock (fracs, brittle) may enhance SRV and production

Shale Fracture CharacteristicsDefinition of Brittleness from Rock Mechanics

SPE 115258

Haynesville

Marcellus Eagle Ford

Woodford

Marcellus g

Barnett

ood o d

70.00 56.00 42.00 28.00 14.00 00.00

BRIT

Barnett – example pump schedule

4000 ft laterals Span = ± 400 ft gal ppg prop lbs rate time

pad 100000 80 29.76 Stage size = 15,500 bbl/stage Prop volume = 4300 sks/stage Number of stages 6 → 8

P t 60% 100 h

pad 100000 80 29.76slurry 40000 0.3 100 mesh 12000 80 12.07slurry 40000 0.5 100 mesh 20000 80 12.18slurry 100000 0.6 100 mesh 60000 80 30.58slurry 100000 0.7 100 mesh 70000 80 30.71

Prop type: 60% 100 mesh, 40% 40/70

Rate = 70 BPM End sand conc = 1 25 – 1 5 ppg

yslurry 100000 0.8 100 mesh 80000 80 30.85slurry 100000 1 40/70 100000 80 31.12slurry 70000 1.25 40/70 87500 80 22.02flush 12000 80 3.57

End sand conc = 1.25 – 1.5 ppg Treating pressure = 4000 psi SRV (ft3)= 4/3*π*ABC

A=network width

% 100 mesh 56.34% total lbs 429500 lbs% 40/70 43.66% total time hr 3.38 hr% pad 15.38%A network width

B=frac lengthC=height/2

avg ppg 0.66 ppg

lbs 100 mesh 242000 lbslbs 40/70 187500 lbstotal volume 650000 gal 15,476 BBL

Formation hardness and proppant embedment

90

70

80

50

60B

HN

#

30

40

B

10

20

19

0Woodford Marcellus Floyd Eagle Ford Haynesville Bossier Barnett CV Lime Ohio SS Coal

Haynesville - example pump schedule

6 perforation cluster - 72 BPM

Stage Fluid Volume Prop Prop Concent Rate/cluster1 Treated Water 36000 -- 122 Guar (R11) 15000 100 mesh 0.5 12 7500 lb3 Guar (R11) 20000 100 mesh 0.75 12 15000 lb4 Guar (R11) 25000 100 mesh 1 12 25000 lb5 HYBOR G (R27) 20000 -- 126 HYBOR G (R27) 45000 Main Proppant 0.5 12 22500 lb7 HYBOR G (R27) 45000 Main Proppant 1 12 45000 lb8 HYBOR G (R27) 45000 Main Proppant 2 12 90000 lb( ) pp9 HYBOR G (R27) 36000 Main Proppant 3 12 108000 lb

10 HYBOR G (R27) 22500 Main Proppant 4 12 90000 lb11 Guar (R11) flush 12

Total fluid volume per stage 309500 gal Total proppant per stage 47500 lb 100 mesh355500 lb Main Proppant355500 lb Main Proppant

Pump Time per Stage 102 minutes

12 Stages per Well Main Proppant = 40/70 PowerProp orVolume / Well = 3,714,000 gal 40/80 HydroProp or100 mesh / Well = 570,000 lb % pad = 37% 30/60 CarboProp orMain Proppant / Well = 4,266,000 lb 30/50 InterProp or

20/40 InterPorpEstimated Pipe Friction = 3300 psiEstimated Perf Friction = 1200 psiBHTP = 11500 psi 6 perf clusters

20

p pPh = 5000 psi Volume / Cluster = 51,583 galSurface Treating Pressure = 11000 psi 100 mesh / Cluster = 7,917 lb

Main Proppant / Cluster = 59,250 lb

Simultaneous fracturing results

• Simulfrac or Zipperfracpp

– Typically more microseismicmicroseismicactivity

– Overlapping microseismicmicroseismicbehavior

– Still see general fracturing behaviorfracturing behavior

SPE 119896 (Rimrock)

Barnett - refrac potential

Barnett Shale: Gel Frac Barnett Shale: Refrac – Water Frac

1000

1200

1400

1600

ate

(Mcf

/d)

Gel Frac Water Frac

SPE 115771

SRV vs. 6-month Average

2500

3000

3500

(MC

FD)

0

200

400

600

800

Gas

Flo

w R

a

y = 20.284x + 319.3R2 = 0.5571

0

500

1000

1500

20006-

Mon

th A

vera

ge

22

00 180 360 540 720 900 1080 1260 1440

Time (days)

0 20 40 60 80 100 120 140

SRV (106 m3)

Marcellus - more height growth & planar vs. Barnett

• Experiment– Lite fracLite frac

• 3000 ft lateral• 6 stages• 550,000 gal/stg Barnett

• 97 bpm rate• 100,000 lb/stg• Slickwater

• Typical– More planar than

Barnett– Complexity

• More stages• More perf clusters

SPE 131783 Range Resources Corp

Haynesville - significant height growth

• Haynesville– GMX fracture treatment

3 000 5 000 ft laterals– 3,000 – 5,000 ft laterals– 7 – 10 stages

• 300 ft spacing• 2 perf clusters/stage

– Stimulation• 300 to 500 K gal/stage• 65 bpm rate• 270,000 lb proppant/stage• Slickwater, hybrid, & X-link

SPE 12507 GMX Resources

Woodford - containment

Carr Estate 13-1H Pettigrew 19-1HObs Well #1 Obs Well #2 Obs Well #1Fracture Lengths•Stage 1: 2500’

Pettigrew 18-1HTreatment Well

•Stage 2: 3300’ •Stage 2 RF: 1400’

•Stage 4: 1200’

WoodfordFM

WoodfordFM

Fracture Heights•Stage 1: 250’

FMFM•Stage 2: 280’

•Stage 2 RF: 280’•Stage 4: 280’Well contained

Stage 1 events

Stage 2RF eventsSt 3 t

Stage 2 eventsStage 1 events

Stage 2RF eventsSt 3 t

Stage 2 eventsStage 1 events

Stage 2RF eventsSt 3 t

Stage 1 events

Stage 2RF eventsSt 3 t

Stage 2 events

•Well contained

Stage 3 events Looking NWStage 3 eventsStage 3 eventsStage 3 events Looking NWSPE 110029Antero

Utica Woodford Barnett Haynesville Marcellus Eagleford Bakken

Porosity (%) 1-8% ~1.5 – 6 (Avg. ~3.8) 8 - 15% 3 – 8% 3- 15% 2 - 12 %

TVD (ft) 6,000 – 14,000 5,400 – 9,500 10,500 – 14,000 4,500 - 8,500 5,000 - 13,000 8,000 - 11,000

Thickness (ft) 100 - 220 100 - 500 60 - 350 50 - 300 40-500 6-15ft & 80-145 ft

BHT (° F) 150-225 150 280-380º F 100-150 150 - 350 190 - 240

TOC (%) 3-9% 4-8% 2-5% 3-10% 0.5-9% Upper-11%-40%Lower=8%-21%

Press Grad (psi/ft) .45-.68 0.52 0.85 - 0.93 0.4 - 0.7 0.4 – 0.85 0.5 - 0.6

Frac Grad (psi/ft) .7-.9 ~0.6 – 0.75 >0.90 0.9 – 1.2 .88-1.1 0.70 – 0.85

Avg Perm (μd) 0.05-0.4 0.05 – 0.4 <0.005 0.5 - 2 400-1200 20 - 500

Sw (%) 33% <35 no free water <25 10-30 25 - 60

Lithology (%) Silica- Chert 30-60% Silica rich 35-50 v/v Shale is soft (ductile)Calcite rich-in areassilica rich (in areas)

organic rich

Variable formation properties

Illite clay-dominatedQuartz/Plagioclase/

F ld

~3-5% carbon content

High Illite-dominate clays

L k lik “ k

Silty, sandy, dolomite grading to laminated shaly interval. Some

natural fractures.Below is Sanish? High clay mineral

fractionFeldspar

CarbonatesSiderite/Pyrite

Looks like “poker chips”

High in Calcites

Below is Sanish

YM (x106 psi) 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2 - 4Middle=4-6

PR (%) 0.15-0.25 0.13-0.25 0.23 – 0.27 0.19 – 0.23 0.20-0.27 Upper/Lower=-0.25-0.28

?0.28

Middle= 0.2 – 0.25

Quartz, wt % 25-54 40-60 25-52 10 - 40 1—30 15 - 70

Plagioclase feldspar, wt %

7-13 2-5 8-17 0 – 10 0-17 1 - 3

C l it t % 7 20 5 30 13 44 5 20 25 95 15 65Calcite, wt % 7-20 5-30 13-44 5 – 20 25-95 15 - 65

Smectite,wt % 2-8 1-5 - < 2 0-23 2 - 6

Illite, wt % 17-46 5-25 12-20 25 - 60 1-50 1 - 13

Kaolinite wt % 0 0 - < 2 0-14 0 - 2

Chlorite, wt % 1 0 4-7 0 – 10 0-7 1 - 3

R (M t it f 0 75 1 45 0 6 1 6 1 1 2 0 8 3 0 0 75 2 16 0 45 0 60Ro (Maturity of Shale)

0.75 – 1.45 0.6-1.6 1 – 1.2 0.8 – 3.0+ 0.75 – 2.16 0.45 – 0.60

Marcellus shale – frac height vs aquifer depth

Thank You