A New Approach for Designing Steam Splitters and Inflow ... · 6/10/2013 1 A New Approach for...

6/10/2013

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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


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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


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


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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


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


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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


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.

0

10

20

30

40

50

60

70

80

90

100

0

6,000

12,000

18,000

24,000

30,000

36,000

42,000

48,000

54,000

60,000

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400

Oil

Pro

du

ctio

n P

ote

nti

al D

istr

ibu

tio

n [

%]

Oil

Pro

du

ctio

n P

ote

nti

al

Length [m]

Initial Oil Production Potential

Initial Oil Production Potential %

50% of oil potential

38% of the well length






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Slide 9

Initial Oil Production Potential Distribution Versus Geology

Dina

Devonian

Shale

Cummings

Dirty Channel/Mud Injector

Producer


STEP I: Investigate the impact of Steam Splitters and Inflow Control

Devices on SAGD performance and the quantity of each

Slide 10

Using GDAs in the Injector and Producer is beneficial. In the first year of SAGD, having One

Production GDA with no Injection GDA, increases oil production by 11.5%. Using only One Injection

GDA with no Production GDA increases oil production by 38%. Using both Production & Injection

GDAs increases oil production by 45% in the first year. These values are just for the number, size

and location of the ports mentioned in the above table for this reservoir.

We can achieve the optimum wellbore dynamics with one GDA in each producer and injector

wellbore.


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Why first year of performance forecast?

Slide 11

Impact of GDAs on

performance is more

significant in the first year.

Models with Injection GDA

Models without Injection GDA


STEP I - Initial Oil Production Potential distribution along the well pair

and Convection Heat Transfer distribution along the Injector

Slide 12

Ranking based on oil production and convective heat transfer: Case 1-2-3-4, 5, 7, 6, 8, 0


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STEP I – Steam chamber growth after 1 year

Slide 13

Ranking based on oil production and convective heat transfer: Case 1-2-3-4, 5, 7, 6, 8, 0

The pictures below show

oil saturation on this layer

Heel Toe


STEP II: Determine the number of ports for the Injector GDA

Slide 14

The increase in the number of Injector GDA ports did not result in any

significant changes in the overall oil production/performance.

Evaluation of convective heat distribution and oil production potential along

the well pair after 6 and 12 months suggested that an Injection GDA with 14

ports gives the best conformance.


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Slide 15

The increase in the number of Production GDA ports from 1 to 8 did not

significantly change the overall oil production/performance. All the runs

were made for a 14 port Injection GDA.

Evaluation of convective heat distribution and oil production potential

along the well pair after 6 and 12 months suggested that a Production

GDA with 4 ports gives the best conformance.

STEP III: Determine the number of ports for the Producer GDA


Slide 16

Benefits of using Injection GDA

For the same Pressure, Temperature & Steam Quality at the heel of injection tubing, the cases

without GDAs and with GDAs report the steam rates of 241 and 350 m3/d CWE respectively.

Using injection GDA, we can inject at higher steam rates with lower pressure drop in the horizontal

wellbore. In this case ~200 m3/d CWE of steam leaves the tubing through GDA and only 150 m3/d

CWE of steam flows through the toe. Therefore, there is a lower friction pressure drop from the

GDA to the toe (slower slope). This results in thermal efficiency improvement.

Inside Injection Tubing

Annulus ΔP=~200-300 kPa

Blue: No GDA case

Red: Optimum Case

GDA

ΔP=325 kPa

ΔP=510 kPa

Pressure Profile for the same BHP & Steam Quality at the heel of the Injection Tubing


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Slide 17

Benefits of using Injection GDA (cont’d)

Using injection GDAs, for the same flow conditions at the heel of the injection tubing (P, T & Steam

Quality), we can inject at higher steam rates and the injector annulus would be at higher pressure

and temperature.

Using injection GDAs will result in uniform draining of two sides of the mud channel. The

temperatures on both sides of the channel are similar.

Blue: No GDA case

Red: Optimum Case

ΔT=3 oC

Temperature Profile for the same BHP & Steam Quality at the heel of the Injection Tubing


Slide 18

Benefits of using Production GDA

The pressure drop along the producer annulus in the case of using no GDAs is 54 kPa, while for

the optimum case with GDA is 7 kPa. Using production GDA results in a more uniform pressure

in the producer annulus. This helps to avoid steam production/short-circuiting.

Using production GDA, 56% of the produced liquid enters the production tubing/scab liner

through the GDA. Hence, pressure drop from the toe to the GDA location is much less in the

case of using production GDA compared with the case with no production GDA.

Inside Scab Liner

Annulus GDA

Blue: No GDA case

Red: Optimum Case

Pressure Profile


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Slide 19

Summary

A work flow for designing Steam Splitters & Inflow Control Devices

in SAGD operations was presented. The approach includes both

reservoir and wellbore flow modelling.

The benefits of using both Steam Splitters & Inflow Control Devices

were shown using FlexWell.


Sponsors

20 RESERVOIR SIMULATION GROUP

6/10/2013

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Thank You

A New Approach for Designing Steam Splitters and Inflow ... · 6/10/2013 1 A New Approach for...

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