BP Optimizes Drainage of More Than 100 Million Barrels

CASE STUDY
BP Optimizes Drainage of More Than 100 Million Barrels
of Secondary Oil from Reservoir Offshore Azerbaijan
Permanently installed WellWatcher BriteBlue DTS fiber reveals flow rate changes in real time
Find a faster, more efficient way to monitor
reservoir performance in highly deviated
wells and minimize risk of poor drainage.
SOLUTION
Install permanent WellWatcher BriteBlue*
multimode DTS fiber outside the gravel-pack
sand screens over the reservoir interval.
RESULTS
Optimized reservoir management and
improved drainage without requiring an
intervention to run production logging tools.
Develop strategy to optimize drainage
BP was developing a portion of the Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea
offshore Azerbaijan. The main producing formations consisted of layers of sandstone interbedded
with shale. More than 100 million barrels of secondary production were at risk of being bypassed
because of the reservoir’s characteristics. The development and management strategies
required a good understanding of the conformance between the producer and injector wells
both by geography and by formation. The use of conventional monitoring technologies, such
as production logging, would have shut down production while the tool was being run inhole,
increasing rig time and costs. The operator needed a faster, more efficient way to manage
reservoir performance.
Use DTS fiber to identify reservoir properties and calculate flow rate
BP chose to install Schlumberger WellWatcher BriteBlue multimode DTS fiber. The optical fiber
provides distributed temperature profiles that can be monitored at the surface in real time, and—
unlike production logging tools—it requires no intervention after installation. The fiber was installed
on the outside of the fiber-optic-compatible gravel-pack sand screens over the reservoir interval.
Placing it there enabled the fiber to react to the temperature changes of each flowing layer.
Fluid flows from a reservoir into a wellbore because of a pressure drop. This fluid movement and
subsequent Joule-Thomson effect cause the fluid to change temperature from its normal geothermal
value. When the reservoir fluid passes through the sand screen to the wellbore, it mixes with the
flow coming up the basepipe from layers below, and the temperature again changes. These two
3,700
Flow rate, bbl/d
100,000
0
200,000
DTS: 8 August
3,800
Thermal well model
Joule-Thomson
inflow temperature
3,900
Depth, m
CHALLENGE
4,000
Flow distribution
4,100
Geothermal gradient
4,200
4,300
65.0
Gamma ray–defined reservoir intervals
70.0
75.0
Temperature, degC
The geothermal gradient, Joule-Thomson effect, and axial mixture temperatures were used to create the thermal
well model for the three reservoir zones (pink, blue, and green) and to calculate the flow distribution model.
3,700
Completions
DTS: 2 October
3,800
DTS: 8 August
3,700
Flow rate, bbl/d
100,000
0
200,000
DTS: 8 August
CASE STUDY: Permanently installed WellWatcher BriteBlue DTS fiber reveals flow rate changes in real time
3,800
Thermal well model
Depth, m
temperatures—Joule-Thomson and axial mixture, along with reservoir properties and well
Joule-Thomson
test3,900
data form the basis of a thermal well model, which is calculated using
THERMA* thermal
inflow
temperature
modeling and analysis DTS software.
4,000 the thermal well model and the actual measured DTS profile produces an initial flow
Matching
profile. As the temperature profile changes over time, the model can be recalibrated by historyFlow distribution
matching the gauge information
and adjusting the rest of the parameters to enhance water
4,100
injection and reservoir management.
Geothermal gradient
Improved reservoir management
strategy and optimized drainage of secondary oil
The4,200
continuous temperature profiles of individual reservoir zones, made possible by the WellWatcher
BriteBlue DTS fiber, enabled the effects of differential depletion to be monitored over time. As a result,
Gamma ray–defined
reservoir
intervalsand oil drainage—optimizing
BP improved its reservoir management
strategy for
water injection
the4,300
drainage
of
more
than
100
million
barrels
of
secondary
oil. The lessons learned from this project
65.0
70.0
75.0
contributed to well placement decisions for future
wells
and
led BP to deploy the WellWatcher
Temperature, degC
BriteBlue DTS fiber in its subsequent ACG operations.
3,700
DTS: 2 October
DTS: 8 August
3,800
Depth, m
3,900
Depletion
4,000
4,100
4,200
4,300
65.0
Gamma ray–defined reservoir intervals
70.0
75.0
Temperature, degC
Reductions in the temperature profile from August to October revealed the layer (pink) where depletion had
occurred. From this information, a new flow distribution model was created, and changes to the reservoir
management strategy were put in place.
slb.com/wellwatcher
*­ Mark of Schlumberger
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