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Microseismic Interpretations and Applications:
Beyond SRV
MicroSeismic, Inc. User Group Meeting
Wednesday, February 19, 2014
Craig Cipolla, Hess Corporation
Reference: SPE 168596
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Stimulated Reservoir Volume (SRV)
• First introduced by Fisher et al. (2004), Barnett Shale. o Fracture growth may be much more complex in unconventional
reservoirs.
o Microseismic volume could be correlated to production in specific areas.
Figure 22 from SPE 90051 Figure 4 from SPE 90051
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Stimulated Reservoir Volume (SRV)
• Further defined by Mayerhofer et al. (2008) o Drainage volume may be limited to SRV.
o Fracture area is a key factor that controls productivity.
Figure 11 from SPE 119890
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SRV-based Production Models
Figure 4 from SPE 90051
xf
ksrvkm
kfwf
The Missing Link The relationship between fracture geometry and conductivity and
well productivity and drainage volume.
Reference: SPE 168596
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What is Stimulated Reservoir Volume (SRV)?
• Completion/Fracturing Engineers
– Microseismic volume
– Fracture geometry
– Maximum drainage distance
• Reservoir Engineers
– Drainage volume or area
– Stimulated region permeability, ksrv
– Effective fracture length
Focus on Microseismic
Focus on Production
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Beyond SRV Microseismic Image
Natural Fractures (DFN)
Stress Regime (3D MEM) Hydraulic
fracture
Natural
fracture
Network Fracture Model
Complex Hydraulic Fractures
calibration using microseismic data
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Beyond SRV Complex Hydraulic Fractures
Numerical Reservoir Simulation
• Discretely grid the complex hydraulic fracture
• Propped and un-propped fractures
• Stress sensitive fracture conductivity
Maintain the fidelity between the hydraulic fracture model and
numerical reservoir simulation
Pressure distribution at 10-years
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Shale Gas Example: Microseismic
~4500 ft Lateral Cased & Cemented, Plug & Perf, 4 clusters/stage, 70 bpm
Hybrid Treatment Design: 12% 100-mesh, 75% 30/50 ceramic, 13% 20/40 ceramic
15 stages 109,000 bbls 4,400,000 lbs
Pi = 7650 psi
Ø= 4.7 %
Gas GR= 0.65
h= 132 ft
Tr= 180oF
Reference: SPE 168596
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Shale Gas Example: Microseismic Volume SRV/ESV = 1800 MMft3
Hydraulic fracture area = ?
Fracture conductivity = ?
Distribution of conductivity = ?
Propped & un-propped fracture area = ?
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Planar Fracture Model
Microseismic observation well
Fluid Efficiency ~ 76%
Total fracture area = 36 MM ft2
Total propped area = 13 MM ft2
Fracture area-pay = 14 MM ft2
Propped area-pay = 5 MM ft2
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Planar Fractures Matched to MSM
Area =17.9 MMft2
Propped = 7.3 MMft2
Area-Pay = 12.2 MMft2
Prop-Pay = 5.4 MMft2
Fluid Efficiency ~ 42%
Microseismic observation well
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Complex Fracture Modeling: 50 ft DFN
50 ft DFN
50 ft DFN Network
Fracture
Geometry
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Complex Fracture Modeling: 50 ft DFN
Total fracture area = 29.7MM ft2
Total propped area = 8.4MM ft2
Fracture area-pay = 16.1MM ft2
Propped area-pay = 3.7MM ft2
Average xf ~ 400 ft Proppant concentration ~ 0.5 lb/ft2
50 ft DFN
Microseismic observation well
Fluid Efficiency ~ 74%
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Complex Fracture Modeling: 50 ft DFN
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Production Modeling
Shale Gas Example
15 stages, 4 clusters/stage
4,571 kgal, 4,430 klbs
Reference: SPE 168596
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Reservoir Simulation Model Grid: 50-ft DFN Discrete gridding of the hydraulic fracture maintains the fidelity between
the fracture model and reservoir simulation
Honor fracture model distribution of propped fracture conductivity and un-propped fractures
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Un-Propped Conductivity
0.01
0.1
1
10
0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000
Co
nd
uct
ivit
y (m
d-f
t)
Closure Stress (psi)
Reference: Suarez, R. 2013. “Fracture Conductivity Measurements on Small and Large Scale Samples – Rock proppant and Rock Fluid Sensitivity.” Slides presented at the SPE Workshop on Hydraulic Fracture Mechanics Considerations for Unconventional Reservoirs, Rancho Palos Verdes, California, U.S.A., 11-13 September.
σmin
Current closure stress
at 4000 psi FBHP
Closure stress at
1500 psi FBHP
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0
1000
2000
3000
4000
5000
6000
7000
8000
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
0 500 1000 1500 2000 2500 3000 3500 4000
BH
P (
psi
)
Gas
(M
CF)
Days
Network Fractures and Planar Fractures
75 ft DFN: 20 nd
50 ft DFN: 25 nd
BHP
History Forecast
BHP 50 ft DFN, UPC~0: 275 nd
Hydraulic fracture complexity can significantly impact recovery
Planar: 32 nd
Understanding matrix permeability is important
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50-ft DFN – Base Case Forecast
Pressures at 10 years 10-yr recovery = 6.0 BCF
km = 25 nd Ø = 5%
Sw=20% H=132 ft
Pi= 7650
Un-propped conductivity may be a key factor when optimizing well spacing
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50 ft DFN (UPC~0)
Pressure distribution at 10-years 10-yr recovery = 6.6 BCF
km = 275 nd Ø = 5%
Sw=20% H=132 ft
Pi= 7650
Un-propped conductivity may be a key factor when optimizing well spacing
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Stage Spacing
15 stages, 4 clusters/stage
4,571 kgal, 4,430 klbs
versus
8 stages, 4 clusters/stage
2285 bbls, 2,215 klbs
Reference: SPE 168596
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0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
0 500 1000 1500 2000 2500 3000 3500 4000
Gas
(M
CF)
Days
Effect of Stage Spacing: 10-yr Recovery
8-stages
50 ft DFN, Network Hydraulic Fractures
15-stages
18% difference in production Almost twice the proppant, fluid, stages (1.875 X)
Over-lap and interference results in lower incremental production compared to planar fractures
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Fracture Complexity & Stage Spacing
0
1
2
3
4
5
6
7
8
50-DFN 75-DFN Planar
1-y
ear
Gas
(B
CF)
Fracture Geometry
8-stages
15-stages18% 24% 69%
1-year
0
1
2
3
4
5
6
7
8
50-DFN 75-DFN Planar
10
-ye
ar G
as (
BC
F)
Fracture Geometry
8-stages
15-stages
18% 17%
38%
10-years
Fracture morphology may significantly impact optimum
stage spacing
More Incremental production for planar fractures
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Tight Oil Example Microseismic Data: ~3000 ft section
500 ft 500 ft
Un-cemented ball-drop completion with swell packers 45 bpm,1600 bbl XL-gel, 110,000 lbs 20/40 ceramic proppant (per stage)
ko = 600 nd
Pi = 7030 psi
Ø= 5.1 %
Bo= 1.82 STB/RB
PBP= 3150 psi
µo= 0.37 cp
co= 1.13E-05 psi-1
h= 77 ft
Rsi= 1552 scf/bbl
Reservoir Data
Microseismic data from ~3000 ft of lateral “adapted” from SPE 166274
Tight oil example incorporates: Geomechanical study (3D MEM) Reservoir simulation history match (3-yrs production)
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333 ft spacing (30 stages/10,000 ft)
Pressure distribution at 10-years
Stage spacing changes fracture complexity and “apparent” system permeability (ksrv)
42,000 bbls
ko=0.0006 md
Two phase flow : Oil and Gas
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192 ft spacing (52 stages/10,000 ft) Stage spacing changes fracture complexity and “apparent” system permeability (ksrv)
51,000 bbls
Pressure distribution at 10-years
ko=0.0006 md
Two phase flow : Oil and Gas
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Linear Flow Analysis: Network Fractures and Stage Spacing
0
0.002
0.004
0.006
0.008
0.01
0.012
0.014
100 150 200 250 300 350 400 450 500
k (m
d)
Stage Spacing (ft)
ksrv could be a function of stage spacing
Actual: ko=0.0006 md, xf~250 ft
xf = 190 ft
xf = 150 ft
xf = 145 ft
Fracture complexity and connectivity may change with different stage spacing
ksrv
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Fracture Complexity and Permeability Assumptions Effect Optimum Stage Spacing
0
10
20
30
40
50
60
70
0 100 200 300 400 500 600 700
10 y
r O
il (M
STB
/100
0 ft
of
late
ral)
Stage Spacing (ft)
RTA results: ksrv = 0.01 md, xf=150 ft
Network fracture model: k=600 nd
(Linear flow analysis, Planar Fractures)
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Conclusions
• The interpretation and application of microseismic images should include mass balance and fracture mechanics.
• Integrating fracture modeling, microseismic data, and production modeling may be required for completion optimization.
• RTA and LFA can provide important insights into well performance, but ksrv and xf may not be appropriate for completion optimization.
• Changes in stage spacing and fracture treatment design will likely result in different “apparent” permeability or ksrv.