Abstract

The paper summarises many years' experience in applying laboratory procedures and heat transfer calculations to the prediction of the start up of flow in a gelled oil pipeline.

The importance of simulating the full scale treatment in the laboratory testing is emphasised by reference to experience in full scale start up trials.

Introduction

The problems of handling waxy crude oils in pipelines are well-known to oilmen. Submarine pipelines are well-known to oilmen. Submarine lines carrying crude oil production to the shore present these problems more acutely than present these problems more acutely than landlines because:-

  1. The cooling rate of the crude oil is higher at all seasons of the year,

  2. Shutdowns are more frequent and may last longer than the 3-day limit which, except in remote areas, is normally assumed forland lines, and

  3. Access to the line at intermediate points is practically impossible, unless special access points are provided when laying the line.

Waxiness can cause two problems in crude oil production. One is the formation of deposits on production. One is the formation of deposits on the pipewall which increase the pressure drop in the pipeline. This occurs when the pipewall temperature is lower than the wax precipitation point (known as the cloud point for distillate point (known as the cloud point for distillate oils, but not so easily identified for crudes). Deposition will not be considered in this paper. The second problem is the possibility of gelation when the production is shut down, or when the line is pumping at a low rate. This can occur when the mean oil temperature is low enough to throw out of solution approximately two per cent or more of the crude was wax, which can form an interlocking gel structure. This paper describes how the likelihood of gelling is assessed, and how the pressure needed to start up the flow in a gelled line is calculated.

PREDICTION OF GELATION PREDICTION OF GELATION

A crude oil does not necessarily gel when it contains two per cent of solid wax. The gelling point depends on the size and the shape of the wax point depends on the size and the shape of the wax crystals and so any pretreatment which affects this size and shape also affects the gelling point. There are other complications: most crude oils contain resins which have a natural affinity for wax crystals. The resins act as natural gelling point depressants: when they collect around the wax point depressants: when they collect around the wax crystals they tend to prevent them from interlocking to form a gel. Thus, any pretreatment which prevents resins from collecting around the wax also raises the gelling point.

To decide whether or not a particular crude oil, which is at the well-testing stage, is likely to gel in a submarine pipeline, it is therefore necessary to measure its gelling temperature after a pretreatment which simulates the normal production procedure. It may also be useful to production procedure. It may also be useful to measure the highest gelling temperature, ie the worst possible condition, in order to make sure that the pipeline could handle the crude should it attain this condition due to an unforeseen variation in the normal production procedure. If the highest gelling temperature is lower than 4 degrees C there should be no gelation of that crude in a North Sea pipeline.

The gelling temperature is normally measured by the pour point test (IP 15, ASTA D97). This test is too well-known to need more than a cursory description here. The oil contained in a one inch diameter pour point tube is cooled in a carefully specified cooling bath. The tube is examined by cautiously tilting it at 3 degrees C intervals, to find the temperature at which the oil ceases to flow.

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