6/10/2013 1 A New Approach for Designing Steam Splitters and Inflow Control Devices in Steam Assisted Gravity Drainage RESERVOIR SIMULATION GROUP Mohammad Kyanpour Zhangxing Chen OUTLINE Introduction to Steam Splitters & Inflow Control Devices Model Description Results & Conclusions Summary Acknowledgements Slide 2 RESERVOIR SIMULATION GROUP
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6/10/2013
1
A New Approach for Designing Steam Splitters and Inflow
Control Devices in Steam Assisted Gravity Drainage
RESERVOIR SIMULATION GROUP
Mohammad Kyanpour
Zhangxing Chen
OUTLINE
Introduction to Steam Splitters & Inflow Control Devices
Model Description
Results & Conclusions
Summary
Acknowledgements
Slide 2
RESERVOIR SIMULATION GROUP
6/10/2013
2
Steam Splitter
Steam Splitters are configured to distribute a customized steam rate at selected
locations. They allow for multiple point injection within a single tubing along the
horizontal liner section of a steam injector well.
Reduces CapEx Cost
• Less tubing strings required
• Simplifies wellhead
• Smaller wellbores
Reduces OpEx Cost
• Improved thermal efficiency
• Reduced surface pressure requirement
Enhances Production
• Uniform steam chamber growth
• Mitigates geological barriers
The size and number of orifices within the steam splitters should be pre-determined
through wellbore flow modelling. Modelling needs to be done to optimize the
placement of steam injection points and the steam rates to achieve a balanced
energy influx into the reservoir.
Slide 3
Reference: Weatherford brochures
RESERVOIR SIMULATION GROUP
Inflow Control Device (ICD)
The Inflow Control Device (ICD) is used in a producer well to develop a uniform
inflow along the horizontal wellbore. This aids in managing the interface between
the injector and producer wellbores for efficient reservoir drainage, while reducing
the tendency for steam breakthrough.
Reduces CapEx Cost
• Less tubing strings required
• Simplifies wellhead
• Smaller wellbores
Reduces OpEx Cost
• Assist in prevention of steam breakthrough
• Uniform or intentional pressure profile along the liner to maximize conformance
Wellbore flow modelling needs to be done to optimize the placement of inflow
control devices and inflow rates through them to mitigate unwanted large pressure
differentials along the production tubing.
Slide 4
Reference: Weatherford brochures
RESERVOIR SIMULATION GROUP
6/10/2013
3
Southern Pacific Senlac Project
Southern Pacific owned and operated since November 2009, previously owned by
EnCana.
Depth: 750 m, Reservoir Temperature: 29 oC, Current Reservoir Pressure:~2,600 kPaa
One pad of 2-3 SAGD well pairs drilled per year.
Currently operating Phases G, H, J and K.
This study was done for J Phase.
Slide 5
RESERVOIR SIMULATION GROUP
Slide 6
24 m
71 m
1,225 m
Number of Grids: 36x71x24=61,344
35mx1mx1m
i x j x k
Inj GDA 1@193 m ICP
Inj GDA 2@858 m ICP
Prod GDA 1@368 m ICP
Prod GDA 2@683 m ICP
Shale
Cummings
Dina
Devonian
Liner Hz Length=1,120 m
Tubing Length=1,085 m (35 m less than Liner)
Liner Size:7” Tbg Size: 4.5” Inst. Tbg: 1.5”
Model Description
RESERVOIR SIMULATION GROUP
6/10/2013
4
Slide 7
Model Description (Cont’d)
Schedule:
1-Three weeks of steam injection into the producer (Bullhead)
2-Shut-in for a Week to install ESP
3-Start SAGD: Steam injection in the injector and production from the producer
Producer Constraints During Bullhead
Producer: Max Steam Injection Rate=400 m3/d CWE
Max BHP=8,500 kPaa
Producer & Injector Constraints During SAGD
Producer: Min BHP=2,200 kPaa
Max Steam Production Rate Allowed in the Wellbore= 0.5 m3/d CWE
Max Liquid Rate=900 m3/d
Injector: Max BHP=3,500 kPaa
Max Steam Injection Rate=350 m3/d CWE
RESERVOIR SIMULATION GROUP
Slide 8
Oil Production Potential
A parameter calculated by STARS which is a function of: permeability, porosity,
pay thickness, relative perm to oil, oil viscosity, pressure and oil saturation.