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Drilling in Salt Formations and Rate of Penetration Modelling
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]

As the industrialization of the world is growing, both energy consumption and demand are steadily increasing. Hydrocarbons have been an important energy provider for several decades, but the production from mature oil and gas producers is now declining. In order to meet this rise in energy demand, new hydrocarbon deposits must be found and produced. Because large oil and gas reservoirs are associated with salt formations, this may be an important energy source for the future. Salt’s low permeability and ability to deform under stress and temperature, makes it an ideal hydrocarbon-trap. The initial objective of this thesis was to establish which challenges are related to drilling for pre-salt hydrocarbons, and propose solutions for how to overcome these challenges. When drilling towards these oil and gas reservoirs, the first problems may occur already in the formations above the salt structures. The density of salt does not increase with burial depth. When its density becomes lower than of the surrounding formations, salt will start to migrate and push through the overlying rocks. Due to the combined effect of compaction disequilibrium and salt tectonics, complex stress patterns can be created in the formations surrounding the salt structures. This may lead to many hazardous scenarios, created by rubble zones and recumbent beds. When drilling inside salt formations, it is salt’s ability to creep and flow that may cause problems. Salt flow may cause borehole deformation that impedes with the drilling and casing operations. When a wellbore has been drilled, salt can creep into the removed rock volume. This may cause situations such as stuck-pipe, hole instability, and high levels of shock and vibration when drilling. Salt flow is a positive function of time, so minimizing the time factor will decrease the possibility of salt flow related problems. One of the measures to minimize exposure time is to perform drilling operations quickly. Hence, a high rate of penetration (ROP) is beneficial when drilling in salt. As part of proposing solutions to the drilling challenges in salt, two new drillbit technologies have been evaluated. These bits may be beneficial in order to overcome many of the problems related to salt drilling. Based on the results obtained in previous studies, these bits are capable of reducing the shock and vibration levels while drilling. This is because these bits are able to drill smoother than conventional PDC bits. Further, the reduced shock and vibration levels will allow an increase in WOB and rotary speed. Based on previous studies, these are the two of the most important parameters to ROP. Thus, these two new drillbit technologies might be able to increase ROP when drilling in salt. Another goal for this thesis was to establish which parameters have the most effect on ROP when drilling in salt formations. Knowing this could help minimize the challenges faced due to salt creep and flow. Therefore, a modelling attempt was performed using Bourgoyne and Young’s ROP model. This model uses multiple linear regressions to calculate a straight line that best fits the data used in the model. In this attempt, data acquired from a well drilled in salt formation was used. Due to lack of variation in the drilling data, several parameters had to be discarded from the model in order to obtain physically meaningful results. This led to only three variables being used in the model. This was weight on bit (WOB), rotary speed of the drillstring, and jet impact force. It was found that the parameter that had most effect on ROP in salt was WOB, followed by rotary speed, and last, jet impact force.

Place, publisher, year, edition, pages
Institutt for petroleumsteknologi og anvendt geofysikk , 2014. , 159 p.
URN: urn:nbn:no:ntnu:diva-25584Local ID: ntnudaim:11816OAI: diva2:736817
Available from: 2014-08-08 Created: 2014-08-08 Last updated: 2014-08-08Bibliographically approved

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