AAPG-SPE 2008 Eastern Meeting Optimal Development of … · AAPG-SPE 2008 Eastern Meeting Optimal Development of Utica Shale Wells AAPG-SPE 2008 Eastern Meeting Optimal Development

AAPG-SPE 2008 Eastern Meeting

Optimal Development of Utica Shale Wells

AAPG-SPE 2008 Eastern Meeting

Optimal Development of Utica Shale Wells

Prepared By:GEORGE KOPERNA, ANNE OUDINOT, JON KELAFANT, VELLO KUUSKRAA

ADVANCED RESOURCES INTERNATIONAL, INC.

11-15 October , 2008Pittsburgh, Pennsylvania

Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions

Outline

Growth in Unconventional Gas Production

0

2,000

4,000

6,000

8,000

10,000

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Year

Ann

ual G

as P

rodu

ctio

n (B

CF)

CBMTGSSHALE

Nearly 50% of Domestic Gas Production

Growth in Shale Gas Production

0

200

400

600

800

1,000

1,200

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Year

Ann

ual G

as S

hale

Pro

duct

ion

(BC

F)

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

WillistonSan JuanOK Fold Belt*Illinois BasinMichigan BasinFort Worth BasinAppalachian BasinArkoma% Lower 48 Prod

Stratigraphic Chart (NY)

Utica Shale Isopach(after Hill, Lombardi, Martin, Fractured Gas Shale Potential in New York)

• IntroductionFlow Testing

• Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions

Outline

Draw Down / Build Up Test

1. 960 psig initial pressure2. 13 day flow period3. 35 day buildup (no radial flow)

1

2

3

Study Well Completion

Modest completion in two intervals• 2514 ft. to 2614 ft.

– 72 shots, 320 sacks sand, 643 bbl slurry, 118 Mcf N2 (15% by volume)

• 2388 ft. to 2502 ft.– 72 shots, 320 sacks sand, 518 bbl slurry,

125 Mcf N2 (15% by volume)

• NOTE: COMPLETION IS PARTIAL

Isotherm Data

Simulation Match Results

-3Skin

ft0.271Wellbore radius

1/psi1.30E-05Matrix Compressibility

1/psi1.00E-04Pore Compressibility

psi400Langmuir Pressure

scf/ft34.2Langmuir Volume (in-situ)

ft10x10x10Matrix Block Size

0.05Phi matrix

mD0.0005k matrix

Days10Sorption Time

0.006Phi fracture

mD0.003k fracture

960 psi @ 2388 ftInitial Pressure

ft226Shale Thickness

ft2388Depth

Match of Build-Up Test(based on reported stabilized rate)

0

200

400

600

800

1000

1200

0 10 20 30 40 50

Days

BH

P, p

si

Test Data Sim Data

Initial Flow rate of 200 Mcfd,Stabilized at 30 Mcfd

• Introduction• Flow Testing

Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions

Outline

Base Case Vertical Well

• Input parameters from match of build-up test used for parametric study

• Well producing at 100 psi BHP for 30 years

• Spacing: 20, 40 and 80 acres• Skin = -3

Grid View – 80 Acre Base Case Vertical Well

X

Y

5

5

10

10

15

15

5 5

10 10

15 15

Prod

Fracture Gas Pres., psia326.4708 1008.8638667.6673497.0690 838.2655

Gas Production Rate –Base Case Vertical Well

0

5

10

15

20

25

30

35

40

45

0 2000 4000 6000 8000 10000 12000

Days

Gas

Rat

e, M

scfd

20 acres 40 acres 80 acres

20 acres 40 acres 80 acresOGIP (Bcf) 1.4 2.8 5.6Cum Prod (Bcf) 0.2 0.23 0.24Recovery (%) 15.6 8.3 4.2

Fractured Vertical Well

• Input parameters from match of build-up test used for parametric study

• Well producing at 100 psi BHP for 30 years• Spacing: 80 acres• Fracture half-lengths of 150 ft, 300 ft and

500 ft• Matrix block size = 10x10x10 ft• Then, impact of matrix block size tested for

a constant half-length fracture (500 ft) at 1 ft and 100 ft

Grid View – Half-length fracture = 300 ftFractured Vertical Well

X

Y

5

5

10

10

15

15

5 5

10 10

15 15

1

Fracture Gas Pres., psia307.8719 1008.8638658.3678483.1198 833.6158

Gas Production Rate – 80 acresFractured Vertical Well

0

50

100

150

200

250

300

350

0 50 100 150 200 250 300 350 400

Months

Gas

Rat

e, M

scfd

150 ft 300 ft 500 ft

150 ft 300 ft 500 ftOGIP (Bcf) 5.6 5.6 5.6Cum Prod (Bcf) 0.42 0.64 0.91Recovery (%) 7.5 11.5 16.4

Warren and Root Model

Gas Adsorbed on Coal

Micro-porosity System

Coal Cleats

Gas Production Rate – Matrix Block Size Fractured Vertical Well – Xf = 500 ft, 80 acres

0

100

200

300

400

500

600

0 100 200 300 400

Months

Gas

Rat

e, M

scfd

1 ft 10 ft 100 ft

1 ft 10 ft 100 ftOGIP (Bcf) 5.6 5.6 5.6Cum Prod (Bcf) 1.15 0.91 0.36Recovery (%) 20.8 16.4 6.4

• Introduction• Flow Testing• Vertical Well Modeling

Horizontal Well Modeling • Field Development• Conclusions

Outline

Horizontal WellMultiple Stages Stimulation• Input parameters from match of build-up

test used for parametric study• Well producing at 100 psi BHP for 30 years• 3,000 ft horizontal length• Spacing: 160 acres• Fracture half-lengths of 150 ft, 300 ft and

500 ft, spaced every 500 ft• Then, impact of matrix block size tested for

a constant half-length fracture (300 ft) at 1x1x1 ft and 100x100x100 ft

3D View – Half-length fracture = 150 ftHorizontal Well

X

Y

5

5

10

10

15

15

20

20

25

25

30

30

35

35

40

40

5 5

10 10

Horiz

Fracture Gas Pres., psia321.6356 912.9314617.2835469.4595 765.1074

Gas Production Rate Fractured Horizontal Well

0

200

400

600

800

1000

1200

1400

1600

0 100 200 300 400

Months

Gas

Rat

e, M

scfd

150 ft 300 ft 500 ft

150 ft 300 ft 500 ftOGIP (Bcf) 10.3 10.3 10.3Cum Prod (Bcf) 1.77 2.27 2.88Recovery (%) 17.2 22.1 28.1

Warren and Root Model

Gas Adsorbed on Coal

Micro-porosity System

Coal Cleats

Gas Production Rate – Matrix Block Size Fractured Horizontal Well – Xf = 300 ft

0

200

400

600

800

1000

1200

1400

0 50 100 150 200 250 300 350 400

Months

Gas

Rat

e, M

scfd

1 ft 10 ft 100 ft

1 ft 10 ft 100 ftOGIP (Bcf) 10.3 10.3 10.3Cum Prod (Bcf) 3.1 2.27 0.63Recovery (%) 30.3 22.1 6.2

• Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling

Field Development• Conclusions

Outline

Field Development

• Impact of “Sweet Spot”intersections:– Increased thickness– Improved permeability

Gas Production Rate – More Thickness Horizontal Well – Xf = 300 ft

0200400600800

1000120014001600

0 50 100 150 200 250 300 350 400

Months

Gas

Rat

e, M

scfd

226 ft 400 ft

226 ft 400 ftOGIP (Bcf) 10.3 18.2Cum Prod (Bcf) 2.3 3.9Recovery (%) 22.1 21.5

Gas Production Rate – More Perm.Horizontal Well – Xf = 300 ft

010,00020,00030,00040,00050,00060,00070,00080,00090,000

0 100 200 300 400

Months

Gas

Rat

e, M

scfd

K K*10 K*100

K K*10 K*100OGIP (Bcf) 18.2 18.2 18.2Cum Prod (Bcf) 3.9 12.5 15.7Recovery (%) 21.5 68.5 86.1

Field Development Summary

86.168.521.56.230.322.1Recovery (%)

15.712.53.90.63.12.3Cum Production (Bcf)

18.218.218.210.310.310.3IGIP (Bcf)

*100*10400 ft100 ft1 ft

PermeabilityThicknessMatrix Block SizeBase1

1Base Case: Matrix Block Size = 10 ft

Thickness = 226 ft

Fracture Half Length = 300 ftK fracture = 0.003 mDK matrix = 0.0005 mD

• Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling • Field Development

Conclusions

Outline

Conclusions

• Production improvements seen with:– Improving reservoir quality

• natural fracture spacing• Permeability (especially matrix perm)

– Improving stimulation intensity

• Recovery efficiency appears low– Similar to early Barnett Shale results

• Down-space• Stimulate separate zones

– Could be “masked” by short-term test/stimulation

Conclusions

• However, it just may be too early to tell:– Two wells– Limited production data– Partial completion– Light stimulation

Questions?

Office Locations

Washington, DC4501 Fairfax Drive, Suite 910Arlington, VA 22203 USAPhone: (703) 528-8420Fax: (703) 528-0439

Houston, Texas11490 Westheimer Rd., Suite 520Houston, TX 77077 USAPhone: (281) 558-9200Fax: (281) 558-9202

Contact Information