Calcium Carbonate and Naphthenate Mixed Scale in Deep-Offshore Fields
- Guy Rousseau (TotalFina Elf) | Honggang Zhou (TotalFina Elf) | Christian Hurtevent (TotalFina Elf)
- Document ID
- Society of Petroleum Engineers
- International Symposium on Oilfield Scale, 30-31 January, Aberdeen, United Kingdom
- Publication Date
- Document Type
- Conference Paper
- 2001. Society of Petroleum Engineers
- 4.2.3 Materials and Corrosion, 4.1.3 Dehydration, 4.1.2 Separation and Treating, 5.4.10 Microbial Methods, 4.3.4 Scale, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics
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Many of the fields that have been or will be discovered in the near future show signs of biodegradation of the crude oil. The result of such biodegradation is a decrease in the amount of the paraffins associated with the formation of naphthenic acids. Some of these crude oils may have a Total Acid Number (TAN) close to 5mg/g. When the reservoir fluid contains a significant amount of CO2, one can expect to find mixed scale of calcium carbonate and naphthenate. The aim of the work conducted was to assess the various factors which affect the formation of mixed scale.
We studied, in particular, the consequences arising from the formation of highly surface-active naphthenates which, depending on the nature of the cations in the formation water, can form stable emulsions , calcium naphthenate deposits or mixed scale of calcium carbonate and calcium naphthenate.
This paper presents the ways to prevent emulsions or deposits resulting from the formation of naphthenates. Chemical prevention is the most commonly used method but problems can sometimes be solved by modifying the way crude is processed. We will also describe an example of a modified process that we plan to use.
The fields recently discovered in deep offshore in Angola, in the Congo or in Nigeria produce an oil with a high acid content. This observation is not limited to West Africa, as some fields from the North Sea and from Venezuela have the same characteristics (shown in Table 1).
The naphthenic acids in petroleum are considered to be a class of biological markers1,2,3, closely linked to the maturity and the biodegradation level of the fields.
The naphthenic acids are found predominantly in immature biodegraded, heavy crudes4. The alteration of petroleum by living micro-organisms, which may occur for example when meteoric water is introduced into an accumulation5, significantly increases the density of the crude and, at the same time, decreases the paraffinic components content.
On the basis of this, we can presume that acidic crudes most likely contain low levels of paraffins and have higher densities than non acidic crudes. The correlation is quite good for all the wells from the same field or all the fields located in the same block.
Table 2 gives some of the characteristics of crudes from Angola block 17: their TAN value, level of paraffin and API degree.
The table clearly shows that the increase in the level of paraffin and in the API degree are associated with a decrease in acidity. The results are illustrated in figure 1 which shows the relation of TAN versus the level of paraffin, and in figure 2 which illustrates the relation of TAN versus API degree.
In addition to corrosion during the refining of acidic crudes, the naphthenic acids are also responsible for two other problems observed in crude processing, resulting from an increase in the pH of the reservoir water:
The formation of mixed carbonate and soap deposits inside tubing or surface installations.
The build-up of stable emulsions associated with the strong surface-active power of the naphthenate group RCOO-.
These problems can be avoided through measures which prevent the pH value of the reservoir water from rising.
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