1. Evaluating Completion Effectiveness
of Horizontal Multi-Staged Fractured Wells
in the Pembina Cardium Field
SPE Tight Oil Workshop
2015-04-29
by Bob Bachman (RBachman@TaurusRS.com)
1
A CGG Company
3. Question
• What metrics are you using to assess your
horizontal wells ?
– Depends on objectives
• Completion Effectiveness
• Ultimate Recovery or Reserves
3
4. Review of Flow Regimes
• SRV Linear Flow
• Compound Linear Flow
• Bounded Flow
4
5. Well is black line
Fractures are solid
gray lines
No flow
boundaries are
dashed gray lines
Flow can only
occur into the well
through the
fractures
SRV Linear Flow
1. Length = Sum of all fracture lengths
which normally can be estimated
Production metric should
be normalized with respect
to number of stages
5
6. Well is black line
Fractures are solid
gray lines
No flow
boundaries are
dashed gray lines
Flow can only
occur into the well
through the
fractures
Compound Linear Flow
2. Length = Distance between toe and heel
fracture treatment
Production metric should
be normalized with respect
to stage spacing
6
7. Completion Effectiveness Requirements
• Want to be in SRV Linear Flow
– Want flow regime to last ~ 1 year
• Need low permeability
– Public monthly data being used
• Cannot be affected by waterflooding
• Can be rate or cumulative
– Candidates
• Maximum oil/fluid rate over 6-7 months
• Cumulative oil/fluid after 1 year
7
8. Pembina Cardium
• Canada’s biggest oilfield
• Discovered in early 1950’
• Waterflood started in late 1950’s
– Light oil
– Heterogeneous with low recovery
• Renewed interest in fringe or ‘halo’ low
permeability areas in early 2000’s
• Multi-stage horizontal fracturing begins
2006
8
9. Pembina Cardium
• Well candidate requirements
– Horizontal wells in sections with no injection wells
• 501 wells
– Review watercut in wells
• Clean-up behavior
• Influence of off-section injection
9
11. Early wells from 2006 through 2009
-½
-1/1
End linear flow tmbo = 800
days or 400 actual days
Late time data being affected
by offsetting waterflood
patterns
First Order Material Balance Time = Cum/q
11
12. Early wells from 2006 through 2009
-½
-1/1
End transient flow tmbl = 1000
days or 500 actual days (one
exception)
Late time data being affected
by offsetting waterflood
patterns
12
First Order Material Balance Time = Cum/q
14. Wells from 2014
from one township
still in linear flow tmbo = 600
days or 300 actual days
-½
-1/1
14
First Order Material Balance Time = Cum/q
15. Wells from 2014
from one township
-½
-1/1
still in linear flow tmbo = 600
days or 300 actual days
Late time data not affected by
any water injection 15
First Order Material Balance Time = Cum/q
16. Wells from 2014
from one township
Water production drops
due to clean-up
Cleanup of completion
fluid 16
17. Final Production Metric Selection
• Cum Oil at 365 days (12 months)
• Normalize on number of stages
17
24. Foamed Water - Median Properties
Well Count = 8
Well Length = 1230 m
Stages = 14.5
Prop/Stage=21.7 Tonnes
Eff Fluid/Stage = m3/Stage
Conc = 173 kg/m3
Comp Cost/Stage = 56.3 k$
12 Month Cum Oil/Stage =309.0 m3
Comp Cost/ 12 Month Cum Oil =29.00 $/stb
24
Eff Fluid = Effective Fluid
accounts for gas volume for foam based fluids
at downhole conditions
When there is no foam, equals base fluid
28. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
OilWat 462.1 25.6
28
Eff Fluid = Effective Fluid
accounts for gas volume for foam based fluids at downhole
conditions. When there is no foam it is same as base fluid
Not many OilWat data samples, a manual review of these
entries showed no clustering of wells within one area.
29. 29
Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
E_SlickW 253.0 35.9
30. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
Water 254.5 45.3
30
31. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
Water 254.5 45.3
E_Water 222.7 54.3
F_Water 309.0 29.0
31
32. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
Oil 195.3 90.7
32
33. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
Oil 195.3 90.7
E_Oil 189.8 91.9
33
34. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
F_Surf 194.5 49.8
34
35. Entries in Table are Median Values
12 Month 12 Month
Fluid Cum Oil/Stage Comp Cost/Cum Oil
m3/Stage $/stb
SlickW 215.6 44.4
F_Water 309.0 29.0
OilWat 462.1 25.6
Final Comparison Plot
35
36. Final Conclusions
• Slickwater is not the optimal fluid for stimulating
the Pembina Cardium
• Polyemulsions were the best
– Were commonly used in the Pembina Cardium for
decades
– Not much current use
• Foams are the second best fluid system
– readily available
36
40. Appendix 2
• Does proppant concentration matter ?
– Need to use example from Montney gas region
recently studied
– Conventional wisdom is that gas needs longer fracture
lengths not more conductivity
• Therefore high proppant concentrations may not be
necessary
– Is this true ?
40
41. Montney Heritage Area
Comparing Slickwater to CO2 Foam
CO2 foam gives superior fracture properties with less
fluid as compared to slickwater
For CO2 foam, more fluid per stage (lower overall
proppant concentration) has negative effect
CO2 foam gives superior fracture properties with
less proppant as compared to slickwater
For CO2 foam, more proppant per stage at high
proppant concentration has positive effect
41
