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dc.contributor.authorNollner, Stephanie P.
dc.date.accessioned2018-07-25T22:43:40Z
dc.date.available2018-07-25T22:43:40Z
dc.date.issued2015
dc.identifier.urihttp://hdl.handle.net/11122/8854
dc.descriptionMaster's Project (M.S.) University of Alaska Fairbanks, 2015en_US
dc.description.abstractThe objective of this project was to evaluate the economic feasibility of producing the upper C sand of the Prudhoe Bay Unit L Pad gas-hydrate-bearing reservoir. The analysis is based on numerical modelling of production through depressurization completed in CM G STARS by a fellow UAF graduate student, Jennifer Blake, (2015). A staged field development plan was proposed, and the associated capital and operating costs were estimated using Siemens's Oil and Gas Manager planning software and costing database. An economic assessment was completed, incorporating the most common royalties, the current taxes laws applicable to conventional gas development, and most recent tariff estimates. The degree of vertical heterogeneity, initial average hydrate saturation, well spacing and well type had a significant impact on the regional gas production profiles in terms of cumulative volume produced, and more importantly, the expediency of gas production. The volume that is economically recoverable is highly dependent on how the field is developed. A field that has higher vertical heterogeneity and corresponding lower average initial hydrate saturation is most economically produced using horizontal wells at 160 acre spacing; the acceleration of gas production outweighs the increased drilling costs associated with the longer wells and tighter well spacing. The choice of development scenario does not impact the project economics significantly given a field that has lower vertical heterogeneity; however, development using horizontal wells at 320 acre spacing is marginally more economic than the alternatives. Assuming a Minimum Attractive Rate of Return of 20%, the minimum gas price that would allow economic production of ANS gas hydrates was found to be $29.83 per million British thermal units; this value is contingent on the reservoir having high average initial hydrate saturation and being developed with horizontal wells at 320 acre spacing. A slightly higher gas price of $36.18 per million British thermal units would allow economic production of a reservoir having low average initial hydrate saturation that is developed with horizontal wells at 160 acre spacing.en_US
dc.language.isoen_USen_US
dc.subjectShale gas reservoirsen_US
dc.subjectEconomic aspectsen_US
dc.subjectAlaskaen_US
dc.subjectNorth Slopeen_US
dc.subjectGas reservoirsen_US
dc.subjectNatural gasen_US
dc.subjectHydratesen_US
dc.titleEconomic assessment of Alaska North Slope hydrate-bearing reservoir regional production development schemesen_US
dc.typeOtheren_US
dc.type.degreems
dc.contributor.chairDandekar, Abhijit
dc.contributor.chairPatil, Shirish
dc.contributor.committeeNing, Samson
dc.contributor.committeeKhataniar, Santanu
refterms.dateFOA2020-03-05T16:30:54Z


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