Reservoir Characterization of the Tweneboa, Enyenra and Ntomme (TEN) Field in the Deep Water Tano Basin Using Seismic Attribute Analyses and Geophysical Well Log Data

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dc.contributor.authorAblordeppey, Worlanyo Kweku
dc.date.accessioned2017-01-23T09:52:15Z
dc.date.accessioned2023-04-18T22:41:24Z
dc.date.available2017-01-23T09:52:15Z
dc.date.available2023-04-18T22:41:24Z
dc.date.issuedSEPTEMBER, 2016
dc.descriptionA Thesis submitted to the School of Graduate Studies, Kwame Nkrumah University of Science And Technology, in partial fulfilment of the requirements for award of degree of Master of Philosophy in Geophysics, en_US
dc.description.abstract3-D Seismic data (Extended Elastic Impedance and reflectivity data) and well log data from five wells were used to characterize reservoirs in the Turonian and Santonian formations of the Tweneboa Enyenra and Ntomme field within the Deep Water Tano Basin. Seismic attributes such as Volume Attribute of Minimum Amplitude (VATMIN), amplitude (reflection strength) and coherency were considered and extracted from the 3-D seismic data. The extracted attributes were successful in delineating two hydrocarbon sand fairways (occurrence zones) labelled as Sovereign-1 and Sovereign-2 in the Turonian formation and one main sand fairway in the Santonian formation. Sovereign-1 sand fairway is a complex sinuous channel system with its sand depositions in a well confined to a relatively narrow channel axis. Sovereign-2 is a mid-slope channelized lobe with a less confined channel axis. Amalgamated straight to slightly sinuous channel system was delineated as the host of the sands in the Santonian reservoir. From the well data analysis, three main reservoir units denoted as R01, R02 and R03 were identified and correlated in Sovereign-1. R01 has average porosity of 17.33 percent, permeability of 183.75 mD, 79 percent hydrocarbon saturation and average net pay of 34 m. R02 has average porosity value of 17.13 percent, 144.45 mD permeability, 65 percent hydrocarbon saturation and 9.4 m net pay thickness. Porosity value of 15.6 percent, 75.5 percent hydrocarbon saturation, 120 mD permeability, and 8.5 m net pay thickness were recorded for R03. Similarly, two main reservoir units namely N01 and N02 were identified in Sovereign-2. N01 has porosity of 16.75 percent, 73.65 percent hydrocarbon saturation, 151.85 mD permeability and 37.3 m net pay. N02 has 17.9 percent porosity, 18.8 percent hydrocarbon saturation, 31.45 mD permeability, and net pay of 6.6 m. Reservoir quality analysis based on porosity permeability cross plot revealed that Sovereign-2 reserve was of good reservoir quality than Sovereign-1. The stock tank of oil initially in place (STOIIP) was estimated to be 456 MMbbl for Sovereign-1 reserve and 388 MMbbl for Sovereign-2 reserve giving a total of 844 MMbbl in the Turonian formation. The results obtained were good indicators for commercial production of hydrocarbons in the field. The petrophysical properties were not estimated for the Santonian sand fairway due to insufficient well log data within the Santonian interval. The Santonian sand fairway was considered unprolific with no well-developed petroleum system.en_US
dc.description.sponsorshipKNUSTen_US
dc.identifier.urihttps://ir.knust.edu.gh/handle/123456789/10152
dc.language.isoenen_US
dc.titleReservoir Characterization of the Tweneboa, Enyenra and Ntomme (TEN) Field in the Deep Water Tano Basin Using Seismic Attribute Analyses and Geophysical Well Log Dataen_US
dc.typeThesisen_US
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