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Optimizing CO2-injection by Compositional Simulation
Norwegian University of Science and Technology, Faculty of Engineering Science and Technology, Department of Petroleum Engineering and Applied Geophysics.
2014 (English)MasteroppgaveStudent thesis
Abstract [en]

Reservoir simulation is used to predict flow of fluids through porous media. The purpose is to get an insight into how the reservoir performs by for exam- ple employing certain injection methods and/or modelling options in order to optimize investment decisions. In this thesis reservoir simulation is used as a tool to aid in the process of simulating hysteresis in one of Statoil's field models. Hysteresis affects the pattern of fluid flow in the reservoir. In order to optimize oil prediction this phenomena is studied. Hysteresis is seldom employed in field models due to its complexity and requirement of computa- tional resources. However, it is an important phenomena which causes change in saturation direction and trapping of fl uid phases. Water-alternating-gas in- jection (WAG) is a method causing rapid changes in saturation direction, but in this thesis CO2-injection has been the main focus. In order to employ hysteresis to the field model, new relative permeability- and capillary pressure curves were made based on experimental data. Corey correlation was used to make gas-oil and water-oil relative permeability curves for the 5 different rock types in the model. Only kr hysteresis was studied due to the fact that enabling capillary pressure caused too many problems for the simulator. Eclipse300 was the selected simulation tool used to simulate the different two-phase hysteresis models available; Carlson's-, Killough's- and Jargon's methods. Carlson's method gave the most optimistic oil predictions while Killough's method gave the least. Jargon's method proved to be the least computational heavy method. However, what all the methods had in common was that a bigger saturation of gas was left in the reservoir compared with the case of no hysteresis selected. A comparison between the different injection methods are also given, where simultaneous water and gas injection proved to be the most cost efficient in terms of oil volumes produced ver- sus the amount of CO2 injected. Injecting at different BHPs was tested to simulate immiscible- and miscible CO2 behavior. An increase in numerical instabilities was observed when BHP was set to miscible conditions, causing severe inconsistencies in calculated relative permeability curves, ultimately resulting in non-physical behavior of the fluid flow. Lastly, a sensitivity analysis of the three-phase models was done, includ- ing ODD3P. The ODD3P model predicts less ultimate oil recovery compared to the traditional models, even though it extends the three-phase saturation range. However, an increase in oil prediction was observed pre-injection. This is due to a different table input and a different way of handling saturation changes, compared to the traditional models. Based on earlier published re- sults done on WAG simulations comparing experimental data with numerical (hysteresis- and non-hysteresis) models[23], the IKU3P model, which ODD3P is an extension of, gave the closest match to the experimental data. Based on this the ODD3P model possibly estimates a more realistic oil prediction compared to the traditional models.

Place, publisher, year, edition, pages
Institutt for petroleumsteknologi og anvendt geofysikk , 2014. , 221 p.
URN: urn:nbn:no:ntnu:diva-25277Local ID: ntnudaim:11682OAI: diva2:733899
Available from: 2014-07-12 Created: 2014-07-12 Last updated: 2014-07-12Bibliographically approved

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