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 Copyright © 2014 Schlumberger. All rights reserved. 14-CO-0257