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Previous Projects

2003-2004: Characterization of Heavy Oils

In 2003-2004 ConocoPhillips, Shell and Statoil sponsored a Heavy Oil JIP. The sponsor companies all had valuable PVT data for heavy oils, which PVT data existing fluid characterization methods had difficulties modeling. A characterization procedure for heavy oils was developed that successfully modeled the phase behavior of heavy oil mixtures with an API Gravity as low as 10. It was further clarified how to avoid the simulated liquid-liquid splits that often cause problems for compositional reservoir simulators. In the same project the Corresponding States (CSP) viscosity model was extended to also cover heavy oils. Some of the oils dealt with in the project had viscosities of several thousand centipoises.

2001-2002: Modeling of Vertical Compositional Variations in Reservoirs with a Temperature Gradient 

In 2001-2002 Calsep carried out a JIP to model the influence of a temperature gradient on the compositional variation with depth in a petroleum reservoir. The influence of gravity had long been known. Gravity will make the concentration of heavy molecular weight compounds increase with depth. Data from the sponsoring companies, Norsk Hydro and Chevron, showed that the temperature increase with depth seen in most reservoirs strengthens the compositional variation. Calsep developed a model based on irreversible thermodynamics matching the observed compositional trend.

1990-1997: Hydrate Kinetics

In the period from 1990 to 1997 Calsep with support from Mærsk Olie og Gas AS and the Danish Energy Agency conducted two hydrate kinetics research projects. When a well stream carrying formation water is transported in a pipeline, hydrate formation is a potential risk. Adding methanol or other hydrate inhibitor to the well stream can prevent hydrate formation. For economic and environmental reasons it is however desirable to keep the consumption of hydrate inhibitors low. No hydrates will form as long as the pipeline temperature is above the hydrate formation temperature. Hydrates may however form during shutdown and the rate of formation determines how long a pipeline can be shut down before restart becomes impossible. The hydrate kinetics projects carried out by Calsep showed that hydrate formation rate is determined by the transport of hydrocarbon gas components from the gas and oil phases to the water phase. A hydrate kinetics model was developed and is today the backbone in the hydrate kinetics module of Calsep's flow assurance pipeline simulator - Flowasta.

1989-1990: Development of Wax Models and Measurement Techniques 

In 1989-1990 Calsep headed a research project within wax precipitation from reservoir fluids. Oil companies with licenses to explore in the Danish sector in the North Sea had to support oil and gas research in Denmark. Statoil spent some of that money on a joint project between Calsep, The Risø National Laboratories and Statoil. Four publications in Energy and Fuel from 1991 describe the results of the work, which include wax formation temperatures measured using 3 different techniques, amount of wax precipitated below the wax formation temperature and a new model for simulating wax precipitation. These articles are still some of the most cited wax articles in literature.

1985-1986: Hydrate Equilibrium Model Development 

With support from Danish Department of Energy and with participation from Danish engineering companies Calsep in 1985-1986 conducted a project to develop a gas hydrate equilibrium model. Gas hydrates had become a problem in Danish gas storages and was also seen as a potential problem in the Danish part of North Sea when the pipeline network was further developed. The gas hydrate adsorption model developed in the project is still the backbone of the PVTsim Hydrate Module.

1982-1985: C7+ Characterization 

In the early 1980s Statoil entrusted Calsep the challenging job of developing a new C7+ characterization procedure. Statoil had decided to set new standards for EoS modeling of reservoir fluids. The key was improved compositional analyses. Until that time it was seldom to see reservoir fluid compositions to higher carbon numbers than C7+. Statoil made True Boiling Point (TBP) analyses to C20+ or even C30+ and later on high temperature liquid chromatography analyses. This compositional data material showed that the logarithm of the mole fraction of a C7+ mole fraction decreases approximately linearly with carbon number. This was the start of the era with predictive EoS modeling. Regression could be limited to fine-tuning and cases requiring heavy lumping.


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