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dc.contributor.authorZanganeh, Behnam
dc.date.accessioned2014-10-25T00:29:45Z
dc.date.available2014-10-25T00:29:45Z
dc.date.issued2014-05
dc.identifier.urihttp://hdl.handle.net/11122/4569
dc.descriptionThesis (M.S.) University of Alaska Fairbanks, 2014
dc.description.abstractHorizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. The Shublik shale, a major source rock for hydrocarbon accumulations on the North Slope of Alaska, has huge potential for oil and gas production, with an estimated 463 million barrels of technically recoverable oil. This thesis presents a workflow for proper modeling of flow simulation in shale wells by incorporating results from hydraulic fracturing software into hydraulic fracture flow modeling. The proposed approach allows us to simulate fracture propagation and leak-off of fracturing fluid during hydraulic fracturing. This process honors the real proppant distribution, horizontal and vertical variable fracture conductivity, and presence of fracturing fluid in the fractures and surrounding matrix. Data from the Eagle Ford Shale in Texas was used for this modeling which is believed to be analogous to Alaska's Shublik shale. The performance of a single hydraulic fracture using a black oil model was simulated. Simulation results showed that for the hydraulically fractured zone, the oil recovery factor is 5.8% over thirty years of production, to an assumed economic rate of 200 STB/day. It was found that ignoring flowback overestimated oil recovery by about 17%. Assuming a constant permeability in the hydraulic fracture plane resulted in overestimation of oil recovery by almost 25%. The conductivity of the unpropped zone affected the recovery factor predictions by as much as 10%. For the case investigated, about 25% of the fracturing fluid was recovered during the first 2 months of production; in total, 44% of it was recovered over thirty years. Permeability anisotropy was found to have a significant effect on the results. These results suggest that assuming a constant conductivity for the fractures and ignoring the presence of water in the fractures and the surrounding matrix leads to overestimation of initial production rates and final recovery factors. In addition, the modified workflow developed here more accurately and seamlessly integrates the modeled induced fracture characteristics in the reservoir simulation of shale resource plays.
dc.titleUnderstanding reservoir engineering aspects of shale oil development on the Alaska North Slope
dc.typeThesis
dc.type.degreems
dc.identifier.departmentDepartment of Petroleum Engineering
dc.contributor.chairHanks, Catherine
dc.contributor.chairAhmadi, Mohabbat
dc.contributor.committeeAwoleke, Obadare
refterms.dateFOA2020-03-05T09:11:31Z


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