A subsea infrastructure in the Gulf of Mexico was experiencing flow assurance challenges due to both hydrate and paraffin formation.

Dry tree wells flowed through individual subsea flowlines to a host processing facility. The condensate had a paraffin content of wt%. Paraffin control chemicals were being deployed with limited success as separator samples contained large amounts of paraffinic solids.

Pour point work showed the incumbent chemical injection had very little effect. A new product was developed to reduce the pour point to create a transportable slurry of production fluids. Cold finger experiments yielded excellent inhibition and confirmed the poor performance of the incumbent product.

Field application yielded impressive results with a clear step change in performance. Field measurements showed that deposition was unlikely to be occurring in the flow line. Pour point was also much more suppressed and paraffin content in samples was not apparent.

Hydrate formation on the same complex was occurring in a separate remote satellite well that was produced through a 10 mile subsea flowline. Daily shut downs to depressurize the flowline to remove hydrates were required. The major challenge was to reduce the daily incumbent hydrate inhibitor demand into the flowline and prevent any depressurization operations.

Modeling and process compatibility testing led to the recommendation that injection of an alternative LDHI product. Use of the chemical did not cause any fluid separation or foaming issues nor interfere with any other platform chemical applications or processes.

The correct chemical formulation and optimization creating a cost saving in reduced operations and chemical overhead for the operator. Significant value savings were created due to no lost production as shut downs were no longer required.

This paper gives a detailed description of the flow assurance root cause failure analysis, the experimental work to develop new products and results of the field applications.

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