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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
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Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions
Outline
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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
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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
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Stratigraphic Chart (NY)
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Utica Shale Isopach(after Hill, Lombardi, Martin, Fractured Gas Shale Potential in New York)
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• IntroductionFlow Testing
• Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions
Outline
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Draw Down / Build Up Test
1. 960 psig initial pressure2. 13 day flow period3. 35 day buildup (no radial flow)
1
2
3
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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
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Isotherm Data
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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
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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
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• Introduction• Flow Testing
Vertical Well Modeling• Horizontal Well Modeling • Field Development• Conclusions
Outline
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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
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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
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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
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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
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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
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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
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Warren and Root Model
Gas Adsorbed on Coal
Micro-porosity System
Coal Cleats
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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
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• Introduction• Flow Testing• Vertical Well Modeling
Horizontal Well Modeling • Field Development• Conclusions
Outline
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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
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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
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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
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Warren and Root Model
Gas Adsorbed on Coal
Micro-porosity System
Coal Cleats
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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
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• Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling
Field Development• Conclusions
Outline
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Field Development
• Impact of “Sweet Spot”intersections:– Increased thickness– Improved permeability
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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
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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
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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
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• Introduction• Flow Testing• Vertical Well Modeling• Horizontal Well Modeling • Field Development
Conclusions
Outline
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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
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Conclusions
• However, it just may be too early to tell:– Two wells– Limited production data– Partial completion– Light stimulation
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Questions?
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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