Sulphate Removal for Barium Sulphate Mitigation - Kinetic vs.
- Caroline Simpson (Scaled Solutions Limited) | Gordon M. Graham (Scaled Solutions Limited) | Ian Ralph Collins (BP Exploration) | John E. McElhiney (Pratt Technology Management) | Roy A. Davis (Dow Chemical USA)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium on Oilfield Scale, 11-12 May, Aberdeen, United Kingdom
- Publication Date
- Document Type
- Conference Paper
- 2005. Society of Petroleum Engineers
- 4.3 Flow Assurance, 5.2 Reservoir Fluid Dynamics, 2.4.3 Sand/Solids Control, 2 Well Completion, 2.2.2 Perforating, 4.5.10 Remotely Operated Vehicles, 4.2 Pipelines, Flowlines and Risers, 3 Production and Well Operations, 7.1.10 Field Economic Analysis, 4.1.2 Separation and Treating, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 4.3.4 Scale, 4.2.3 Materials and Corrosion, 5.3.2 Multiphase Flow, 1.8 Formation Damage, 7.1.9 Project Economic Analysis, 1.3.2 Subsea Wellheads
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Conventionally, scale mitigation is achieved using chemical inhibitors either by squeeze treatment into the reservoir or continuous injection. However, with new fields encountering increasingly more challenging environments, or when the economic impact of chemical intervention by squeeze treatment is large (e.g. subsea fields with poor bullhead chemical placement), other methods of scale control such as the use of low sulphate sea water (LSSW), must be considered during the front end engineering and design (FEED) stage of a field development. Nevertheless, for conventional sulphate reduction packages (SRP's) that reduce the sulphate concentration in the injected sea water typically towards 40 - 50 ppm, there remains a residual scaling risk and the requirement for periodic squeeze treatments.
Previous work reported at the 2004 SPE Oilfield Scale symposium (SPE 87465) examined the level of sulphate reduction required to mitigate the requirement for even periodic squeeze treatments against barium sulphate scale.This showed that sulphate levels of 20 ppm were required in order to prevent scale formation under down hole production conditions, although it was also demonstrated that thermodynamically the system remained oversaturated with barium sulphate.
This paper expands considerably on this preliminary "field specific" case and examines the impact of LSSW on the scaling kinetics across a broad range of formation water compositions (barium ranging from 150 ppm to 650 ppm) and at temperatures between 80ºC and 120ºC. The paper therefore investigates the relationship between scaling kinetics and thermodynamics in relatively mild scaling environments and illustrates that whereas extremely low levels of sulphate would be required to completely prevent scale from a thermodynamic viewpoint, the kinetics of scale formation may prevent scale precipitation under down hole production conditions, with additional continuous injection inhibitor applied at wellheads to protect flow lines etc.In summary, this paper presents results from an extensive series of long term dynamic flow and pseudo static performance tests designed to determine the relative impact of thermodynamics and kinetics on the residual barium sulphate scaling risks associated with the injection of LSSW for pressure support.
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