Development and Implementation of a Scale-Management Strategy for Oseberg Sør
- Niall Fleming (Hydro Oil and Energy) | Kari Ramstad (Norsk Hydro A/S) | Synnove H. Eriksen (Norsk Hydro A/S) | Erlend Moldrheim (Hydro Oil & Gas) | Thomas R. Johansen (Hydro Oil & Gas)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2007
- Document Type
- Journal Paper
- 307 - 317
- 2007. Society of Petroleum Engineers
- 2 Well Completion, 4.5.10 Remotely Operated Vehicles, 4.2.3 Materials and Corrosion, 3 Production and Well Operations, 5.1.2 Faults and Fracture Characterisation, 2.7.1 Completion Fluids, 3.3.1 Production Logging, 5.4.10 Microbial Methods, 3.1.6 Gas Lift, 5.2.1 Phase Behavior and PVT Measurements, 5.4.2 Gas Injection Methods, 5.7.5 Economic Evaluations, 4.3.4 Scale, 4.5 Offshore Facilities and Subsea Systems, 2.2.2 Perforating, 4.1.2 Separation and Treating, 5.6.4 Drillstem/Well Testing, 3.2.4 Acidising, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 3.4.4 Downhole Chemical Treatments and Fluid Compatibility, 4.3.1 Hydrates, 5.5 Reservoir Simulation, 5.3.2 Multiphase Flow
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Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130 km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It comprises a sequence of fault-bounded structural units of varying geological complexity. Within these units, the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir support is provided by combined injection of gas and Utsira aquifer water. The wells are a combination of platform and subsea and comprise extended reach horizontals with complex geometry and lesser numbers of vertical wells.
Detailed scale predictions have been performed to identify the scaling risk for each producer. From these, it was identified that the major risk to well performance and integrity was CaCO3 precipitation in the upper tubing with potential failure of the downhole safety valve. The risk varied from negligible to severe and reflected the variable composition of the produced water and well operating conditions. The scale predictions provided the basis for a technical and economic evaluation to identify an appropriate scale-management strategy for Oseberg Sør. For those wells completed with downhole chemical injection lines, the option to use these for scale inhibition was considered cost effective. In other wells where this option was not available, scale inhibitor injection into the gas lift system or squeezing using a viscosified treatment was considered viable.
The paper will provide the technical and economic reasoning for the scale-management strategy selected along with field case histories for each treatment type (i.e., experience with treatment using chemical injection lines, injection of scale inhibitor into the gas lift system, and squeezing).
|File Size||2 MB||Number of Pages||11|
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