Microseismic Interpretations and Applications: Beyond SRV€¦ · Craig Cipolla, Hess Corporation...
Transcript of Microseismic Interpretations and Applications: Beyond SRV€¦ · Craig Cipolla, Hess Corporation...
Microseismic Interpretations and Applications:
Beyond SRV
MicroSeismic, Inc. User Group Meeting
Wednesday, February 19, 2014
Craig Cipolla, Hess Corporation
Reference: SPE 168596
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
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
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
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
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
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
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
Shale Gas Example: Microseismic Volume SRV/ESV = 1800 MMft3
Hydraulic fracture area = ?
Fracture conductivity = ?
Distribution of conductivity = ?
Propped & un-propped fracture area = ?
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
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
Complex Fracture Modeling: 50 ft DFN
50 ft DFN
50 ft DFN Network
Fracture
Geometry
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%
Complex Fracture Modeling: 50 ft DFN
Production Modeling
Shale Gas Example
15 stages, 4 clusters/stage
4,571 kgal, 4,430 klbs
Reference: SPE 168596
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
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
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
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
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
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
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
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
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)
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
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
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
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)
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.