Paraffinic fractions cause two mostly known problems under deepwater cold environments: wax deposition and gelation. These two topics have been addressed for a long time and industry design standards are well established today. However field operating experience and R&D results have shown that there is room for improving design standards. This paper will present a few aspects on this subject.

The first one concerns determining yield stress for gelled oil, a major concern for projects with high wax content crudes. The usual procedure may be overly conservative thus leading either to high pressure pipeline rating or excess of chemical consumption (PPD). A new approach is presented in order to enable a more accurate estimate of the stress needed to break the gel and flow restart.

Regarding wax deposition the general rule is to design the system so to keep the minimum flowing temperature above WAT. It is common to allow the flow slightly below WAT with no deposition, provided the wax solids amount is low enough, as will be presented here. Even so this solution may not be economical for some cases, such as a small deepwater field located northeast Brazil. The project was made to cope with wax deposition by pigging. Operation experience has shown that deposition rate was negligible despite the oil being waxy and flowing well below WAT. This case is analyzed in this paper and an explanation for this behavior is proposed.

In general increasing production flow rate raises stream temperature so reducing wax deposition and other flow assurance issues. However a case history is presented where, given fluid characteristics (high GOR) and riser geometry, decreasing flow rates leads to increasing fluid temperatures.


Flow assurance problems caused by wax fractions are known for a long time and the deposition mechanisms were well established since Burger et al (1981). Despite this fact, wax related problems are still challenging industry in 21st century. Considering Brazilian environment, the discovery of Pre-Salt areas brought back problems that were supposedly already solved. It comes from two facts that together bring difficulties for the flow assurance project. The first one is the Pre-Salt oils wax contents which are much higher than that usually observed in oils produced from zones above the salt layer. The second point is the typical reservoir temperature at the Pre-Salt, lower than at other areas. These two facts mean oils with higher WAT coming from reservoirs at lower temperatures, thus lowering the margins for temperature drop. Besides that, there is still the higher amount of gas (or GOR) that causes fluid cooling while decompressing in upward flow in the risers. This situation requires thicker thermal insulation layer in the flow lines and bottom riser, considering that at riser top the thermal insulation is not effective to prevent temperature drop. This shorter margin between reservoir temperature and WAT requires a more careful heat transfer specification and reducing as much as possible any clearance in the WAT determination.

Oil gelling is a problem that used to happen in some onshore waxy oil fields, located in state of Bahia, Brazil. However these fields are located at a hot environment area and gelling is restricted to specific cases during the winter. Once again some Pre-Salt oils have a tendency to form strong gel if cooled down to temperatures typical of deepwater regions. This adds a new issue to be addressed in order to allow production of such fields.

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