Northshore CK356N6C: High-temperature corrosion control

After turnaround, the refinery returned to a heavy offshore crude slate and reported persistent iron in its vacuum sidestreams. High acidity in those streams added to the concern about high-temperature naphthenic-acid corrosion. The refinery needed to assess treatment within the conditions of the existing unit and its equipment metallurgy.

Downstream units also restricted phosphorus, limiting the inhibitor options the refinery could consider. The product-selection problem therefore combined two requirements: addressing the vacuum-section corrosion concern and fitting the downstream processing constraint. This context explains why the low-phosphorus CK356N6C grade was selected for the application described in the case.

Cestoil sampled the unit's streams and reviewed corrosion history, sidestream temperatures and metallurgy with the refinery's technical department. The treatment concept used the inhibitor's film-forming action within the identified application. Injection planning considered the vacuum tower's intermediate pumparounds and wash-oil reflux as routes for delivering the product.

The source describes three injection points and the streams associated with them. Their locations and flow conditions are included in the detailed report because they are part of the application basis. A different refinery would need to review its own tower configuration, stream temperatures and metallurgy before deciding how to apply the product or assess the relevance of this trial.

The refinery began injection in April 2019 with an initial film-forming period. It then moved to a lower maintenance treatment rate while continuing to process the offshore crude slate. Cestoil and the refinery followed the operating record through to early July, using regular analysis of acidity and iron on three vacuum sidestreams.

The two treatment periods serve different purposes in the case. The initial period records the early application, while the maintenance period shows the subsequent monitored operation at the revised treatment rate. The chronology is important when interpreting the result: the report's percentage comparison is between those two treated periods, rather than between an untreated unit and a treated unit.

Stream iron is an indirect corrosion indicator. It can be useful for following a treatment program, but the 72% change should not be relabelled as a directly measured reduction in equipment corrosion rate. Inspection findings, probes or other refinery corrosion records would provide additional evidence about equipment condition.

The case's paired acidity and iron monitoring is therefore particularly useful. Reading the two on the same stream and over the same period helps the team assess whether feed conditions changed while the iron indicator improved. Treatment history, crude slate and operating events add further context. A comparable evaluation can use that structure while choosing the measurements that best address its own equipment concern.

The refinery recommended linking treatment decisions to crude acidity and reviewing how the inhibitor was dispersed through the process. Its follow-up recommendations included carrier-fluid injection, while the documented trial itself used the existing injection system to dose the product neat. Keeping the trial arrangement and later recommendation distinct helps another operator understand what was tested and what the refinery proposed for improvement.

For a new application, the operating team and Cestoil can review crude and sidestream acidity, injection-stream conditions and downstream phosphorus requirements together. Changes in the crude slate should lead to reassessment of that treatment basis. The case provides a monitored example to inform this discussion; site procedures and equipment conditions determine the program selected for another unit.