Production Optimization in a Campos Basin Reservoir: A Case for Applying Robustness Measures to a Waterflood Project from Subsurface and Operational Design to Execution
- Ozan Arslan (Devon Energy) | Kyle Ross Koerner (BP) | Stephen Knapp (BP) | Nate Biddle (BP) | Alwin Bok (BP) | Paulo Chaves (BP)
- Document ID
- Offshore Technology Conference
- OTC Brasil, 4-6 October, Rio de Janeiro, Brazil
- Publication Date
- Document Type
- Conference Paper
- 2011. Offshore Technology Conference
- 5.1.5 Geologic Modeling, 2.1.5 Gravel pack design & evaluation, 1.8 Formation Damage, 5.1.8 Seismic Modelling, 4.3.4 Scale, 1.6.2 Directional Drilling Systems and Equipment, 4.1.5 Processing Equipment, 3.3 Well & Reservoir Surveillance and Monitoring, 1.7.5 Well Control, 1.1 Well Planning, 4.2.3 Materials and Corrosion, 4.1.2 Separation and Treating, 5.1.2 Faults and Fracture Characterisation, 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 3.1.2 Electric Submersible Pumps, 1.4 Drillstring Design, 1.2.1 Wellbore integrity, 1.10 Drilling Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.1.3 Sand/Solids Control, 5.4.1 Waterflooding, 2 Well Completion, 5.5.8 History Matching, 1.11 Drilling Fluids and Materials, 3 Production and Well Operations, 1.6 Drilling Operations, 5.1.7 Seismic Processing and Interpretation, 6.5.2 Water use, produced water discharge and disposal, 5.1 Reservoir Characterisation
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An asset team presents a successful cross-disciplined workflow used in a Campos Basin multi-producer system waterflood program, from design through execution. The workflow encompassed subsurface characterization, well planning, data acquisition, well controls, and surveillance to support efficient oil recovery. Drilling from a central platform, extended reach wells were required to access a structured series of near-shore, laterally amalgamated channel sands separated by variable barriers posing significant subsurface modeling, well design and drilling challenges. A cross-disciplined team approach employed robustness measures to find a near-optimal solution with controlled risk management.
A full-field reservoir model was built to identify competing injection well locations designed to maximize oil recovery while incorporating the underlying subsurface uncertainties to assess probability of success and model bias. In parallel, drilling difficulty and mechanical constraints were analyzed to high grade risked drilling locations. Further optimization considered drilling and completion design, insitu fluid / injection fluid characteristics and compatibility, injection start-up procedures and long-term injectivity, and waterflooding management.
The simultaneous integration of subsurface and mechanical information reduced the number of injection placement and completion scenarios significantly while helping to rank the critical data gaps. An injection well, a constrained robust solution, was proposed near appraisal well control with multiple intermediate well targets designed to collect critical data for reservoir management and completion design. Thus, the team sufficiently constrained subsurface uncertainties while also highlighting the potential decision points to all stakeholders to allow modifications to the plan in real-time based on the new data.
The predicted injectivity compares closely to the actual injectivity while the predicted production was exceeded due to the confirmation of the desired circuitous injection streamlines, which delayed water breakthrough in the producers (4 months to over a year) as compared to the base prediction and proved up an additional infill producer. The paper includes the examples of how system constraints and potential decision points were addressed across the asset team from the subsurface analysis work to drilling, completion, injection operations, and surveillance measures for optimizing the waterflood program.
The Polvo complex is a system of clastic (Upper Cretaceous) and Macae carbonate (Lower Cretaceous) reservoirs (Figure -1) in the Campos Basin with 18 - 22 oAPI oil gravity range. The clastics have been on production for 3 years with natural water drive and water injection. Development drilling started in mid-2008 for the Cretaceous Sand System (CSS) where wells were completed with open-hole gravel pack and electrical submersible pumps (ESP). All ESPs were equipped with downhole inlet and outlet pressure gauges to provide critical pressure data for reservoir surveillance and optimize pump performance.
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