Ole Torsater

Experimental Investigation of Decalin and Metal Nanoparticles-Assisted Bitumen Upgrading During Catalytic Aquathermolysis

Unconventional oil reservoirs such as heavy oil, extra heavy oil, oil shale and oil sand/bitumen are very interesting since these kinds of oil are currently proven to constitute a huge amount of total world oil reserves. However, it is difficult to handle these kinds of oil due to very high viscosity. Thermal application methods may have great possibilities for heavy oil and bitumen production. Prior to shipment to downstream markets, the bitumen needs to be upgraded to produce higher value of liquid hydrocarbon products. However, the issues in oil sands industry are environmental challenges such as green-house-gas (ghg) emission, huge amount of fuel and water consumption, liquid and solid wastes disposal. The objective of this study is to investigate an effective and efficient upgrading process by adding decalin as hydrogen donor, water and various type nanometal particles (40-500 nm) as catalysts into Athabasca bitumen. Athabasca bitumen has been successfully upgraded by reducing its viscosity about 80% (measured at 60 oC) by applying catalytic aquathermolysis at 240 oC during 12 hours. As hydrogen donor, decalin is very interesting. Besides cheap, it could dramatically accelerate viscosity reduction with concentration of 5 wt.%. The degree of viscosity reduction will increase with increased decalin concentration. However degree of bitumen upgrading will decrease with presence of water. It seems that synergetic effects to the upgrading process did not work effectively. Hence water consumption during aquathermolysis process might be reduced to minimize the cost. Since earlier studies have shown that nanoparticles may reduce heavy oil viscosity, four types of nanometal particles have been studied and some of them accelerated viscosity reduction during catalytic aquathermolysis process at particular concentration. Improper nanometal particle type and concentration are reversed effect. Temperature and heating time have vital role in the upgrading process.

Experimental and Numerical Simulation of CO2 Injection Into Upper-Triassic Sandstones in Svalbard, Norway

Sequestration of carbon dioxide in a saline aquifer is currently being evaluated as a possible way to handle carbon dioxide emitted from a coal-fuelled power plant in Svalbard. The chosen reservoir is a 300 m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is capped by 400 meter shale. Experimental and numerical studies have been performed to evaluate CO2 storage capacity and long term behaviour of the injected CO2 in rock pore space. Laboratory core flooding experiments were conducted during which air was injected into brine saturated cores at standard conditions. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. For most samples, no gas flow was detected in the presence of brine, when employing a reasonable pressure gradient. This poses a serious challenge with respect to achieving viable levels of injectivity and injection pressure. A conceptual numerical simulation of CO2 injection into a segment of the planned reservoir was performed using commercial reservoir simulation software and available petrophysical data. The results show that injection using vertical wells yields the same injectivity but more increases in field pressure compare to injection through horizontal wells. In order to keep induced pressure below top-seal fracturation pressure and preventing the fast propagation and migration of CO2 plume, slow injection through several horizontal wells into the lower part of the “high” permeability beds appears to offer the best solution. The high capillary pressure causes slow migration of the CO2 plume, and regional groundwater flow provides fresh brine for CO2 dissolution. In our simulations, half of the CO2 was dissolved in brine and the other half dispersed within a radius of 1000 meter from the wells after 4000 years. Dissolution of CO2 in brine and lateral convective mixing from CO2 saturated brine to surrounding fresh brine are the dominant mechanisms for CO2 storage in this specific site and this guarantees that the CO2 plume will be stationary for thousands of years.