Carbonate and sulfate scales formed on oilfields under natural depletion or water injection support, can occur on a number of critical points from the reservoir to topside facilities impacting on well productivity.

Scale control has become a challenging task as oil industry tends to go for deeper water with complex completion wells which may produce from harsh environment conditions (HP, HT). Scale management has become a power tool to assure that oil loss due to precipitation along oil production process be avoided and costs associated to its prevention and remediation treatments be minimized.

The most important factor for the success of this approach is that flow assurance strategies are considered in the field planning. Scaling risk analysis should be carried out, assessing scale tendency and intervention difficulties associated with the well design and field features. These issues are addressed in the exploration phase of the field, determining, based on risk analysis and economic evaluation criteria, the appropriate technology to be adopted. In the production phase, production data, down hole pressure measurements as well as chemical monitoring of produced water are essential for diagnosing whether any scale is being formed and to review the decisions made if necessary.

In order to demonstrate the suitability of this approach, cases regarding a siliciclastic turbidite and a carbonate reservoirs in the deepwater and ultra-deepwater fields will be discussed showing different scale management strategies, such as, scale modeling by thermodynamic calculations, scale control by using downhole scale inhibitor injection, scale inhibitor squeeze treatment, scale dissolver treatment, sulfate removal unity, and downhole surveillance instrumentation (PDG, TPT).


In the 1990's the deep water petroleum province in Campos Basin consolidated the Petrobras expertise in Exploration and Production in turbidite reservoirs in the deep and ultra-deep scenarios. The development of technologies integrating production fluid and reservoir characterization, drilling systems, artificial lifting and flow technologies were carried out to overcome the challenge of producing from turbidites in deep waters. In 2000, Petrobras began to increase its exploratory activities in the deep and ultra-deep water regions of the Santos Basin. This resulted in the discovered of several gas and oil fields in the northern areas of the basin in the Late Cretaceous turbidites (1). In recent years exploration began to focus on the São Paulo Plateau, a prominent topographic feature in water depths ranging from 2,000 to 3,000 meters. A continuous Apian evaporitic sequence, thicker than 2,000 meters exists in this region, contrasting with the very thin marine section above. The explored reservoirs are carbonates that occur bellow the salt layer (2). Petrobras obtained a very significant exploratory success in this region. New technologies had to be implemented to enable the development of giant fields as it happened before in 80's and 90's producing the deep water turbidite reservoirs in Campos Basin.

The techniques for scale management have been implemented to deal with the new scenarios of deep and ultra deepwater subsea fields, in the harsh conditions of deep water subsea fields, and deep carbonate reservoirs.

The most common oilfield scales are calcium carbonate and barium, calcium and strontium sulfates. Carbonates can occur as a consequence of changes in equilibrium caused by pressure decrease during the production process. Sulfate scales are caused by incompatibility between rich sulfate sea water and formation water displaying barium, strontium and calcium concentrations.

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