Video: Correlating Calcium Carbonate Scale Risk with Field Experience Data
- Kari Ramstad (Equinor ASA) | Kristian Sandengen (Equinor ASA) | Anthony Frank Mitchell (Equinor ASA) | Erlend Moldrheim (Equinor ASA)
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- Society of Petroleum Engineers
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- 2020. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
- 5.4 Improved and Enhanced Recovery, 4.1.2 Separation and Treating, 4.5 Offshore Facilities and Subsea Systems, 7 Management and Information, 5.4.2 Gas Injection Methods, 4.1 Processing Systems and Design, 2 Well completion, 4.5 Offshore Facilities and Subsea Systems, 4 Facilities Design, Construction and Operation, 1.8 Formation Damage, 5 Reservoir Desciption & Dynamics, 7.2 Risk Management and Decision-Making, 2.6 Acidizing, 7.2.1 Risk, Uncertainty and Risk Assessment, 4.3.4 Scale, 1.8 Formation Damage
- Well design, Scale management strategy, Thermodynamic modelling, Calcium carbonate scale, Field experiences
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Calcium carbonate (CaCO3) scale formation in production wells and process systems is a well-known challenge in the oil and gas industry. Various strategies are selected to prevent scale formation (proactive, e.g. by scale inhibitors) or to remove scale when it has formed (reactive, e.g. by acid treatment), depending on the severity of the problem and the complexity of the production system. Lack of access for remedial actions may be a limiting factor in subsea and unmanned installations and scaling may represent a larger risk of production losses or system failures.
The scale management strategy and design of new wells during field development are based on thermodynamic calculations, kinetic studies and field observations. Experience has shown that wells with high temperature and high pressure drops are more prone to downhole calcium carbonate scaling.
Field experience has been collected and systemized based on operations of oil and gas-condensate fields in the North Sea and Norwegian Sea. The observations have been compared to thermodynamic calculations and aligned to kinetic modelling, defining the critical saturation ratio (SRCaCO3) for scaling. The result is a graphic which has proved to be a powerful tool in planning of new wells and is described in this paper.
The Oseberg field in the North Sea is producing from oil and gas-condensate wells at various reservoir temperatures (98-128°C). The field comprises platform and subsea production systems and one unmanned wellhead platform. Seawater has been injected for pressure support in some areas, while gas injection or depletion are the driving forces in other segments. The CaCO3 scale potential and management strategy have been evaluated for new wells in a field life perspective. Risk of production losses and maximizing cost benefit are key selection criteria, and the variety of wells requires individual solutions. The paper discusses the need for downhole continuous injection of scale inhibitor, compared to batch scale inhibitor squeeze treatments and/or acid treatments. Guidelines for optimum operation of these wells to avoid scaling are presented.