At the Statoil-operated Heidrun-field in the Norwegian Sea, naphthenate deposits were first observed during a maintenance shutdown in September 1996. Thereafter the problem increased, and by the end of 1997 it was recognised as a constant threat against continuous production. The present paper describes both the short-term measures taken to gain control of the problem in the early days, and the quest for a more elegant long-term solution. Statoil is continuously working to increase its fundamental understanding of the naphthenate problems and to improve the naphthenate inhibitors used at the Heidrun field.
Among the oilfields found and developed around the world, an increasing fraction contains naphthenic acids and has a high TAN-value (Total-Acid-Number). A high TAN-number in a crude oil is probably a result of aerobic bacterial degradation and is often linked to high densities and sulphur contents. There are several problems that are specific to these kinds of crudes;
During production these crudes tend to react with the calcium-ions in the formation water and form naphthenates that deposit and plug the process equipment.1–3
Naphthenic acid corrosion is a major concern to the refining industry. The presence of naphthenic acids and reactive sulphur compounds considerably increases the corrosion rates in the high temperature parts of the distillation units.4
Jet fuels, diesel fuels, and heating oils do all have specifications that limit the maximum acid contents in these products.
The present paper addresses itself to the calcium naphthenates formation during crude oil production at the Heidrun oilfield in the Norwegian Sea.
The appearance of the naphthenate problem will be described in detail. Then both short-term and long-term remedies for control are presented.
The Heidrun field in the Norwegian Sea has been producing oil and gas since October 1995 from a floating tension leg platform with a concrete hull.
Heidrun was discovered in 1985 by Conoco, which served as operator for the exploration and development phase. Statoil took over in 1995 as production operator.
Oil from the field is primarily shipped by shuttle tankers to Statoil's Mongstad crude oil terminal near Bergen for onward transport to customers.
Gas from Heidrun is piped to Tjeldbergodden in mid-Norway and serves as the feedstock for the Statoil methanol plant there.
From 2001, the field has also been connected to the Åsgard Transport pipeline. Heidrun gas is piped through this trunkline to Kårstø north of Stavanger and on to Dornum in Germany - a total distance of roughly 1400 kilometers.
A total of 76 wells are planned on the main field, including 51 producers, 24 water injectors and one gas injector.
The north flank of Heidrun was brought on stream in August 2000, enabling Statoil to maintain plateau production for 4 more years until 2004.
Some of the Heidrun crude oil's characteristics are given in Table 1. Of special importance is the combination of a high acid content (TAN = 2.7 mg KOH/g) with relatively low density (0.90 g/cm3) and hetero-element (S, N, Ni, V) content typical for North Sea crude oils. Normally, oils with high acid numbers also have high densities, as is evident from Table 2.
A simplified flow scheme of the liquid treatment systems at the Heidrun platform is showed in Fig. 1. Three gravitation separators constitute the main separator train. The separators have centre inlets, and are fitted with Mellapak (polypropylene) internals (Fig. 2). The well stream enters the inlet separator at 64°C, and is heated further to 77°C upstream of the 2nd stage separator. The water cut is about 18% and 2% at the 1st stage separator inlet and outlet, respectively. The next two separators reduce the water content of the oil to less than 0.5%.