Browsing by Author "Mkinga, Oras Joseph"

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    EOS Model and Black-Oil PVT Table Generation for a Tanzanian Reservoir
    (International Journal of Applied Science and Technology, 2019) Mkinga, Oras Joseph; Kleppe, Jon; Rwechungura, Richard Wilfred; Raphael, Matheo L.
    Tuning of an EOS model and generation of Black-oil PVT tables for a gas field in Tanzania, here named R reservoir, are presented. The Soave-Redlich-Kwong equation of state was tuned using experimental data and PhazeComp software to obtain the EOS model which represents fluid behavior change in the R reservoir. A contribution is provided in a relationship between specific gravity and molecular weight, which is a modified form of Soreide equation for C7+ characterization. Constants of the equation are determined using linear regression to fit experimental data. A residual oil in the reservoir is recognized using EOS calculation; PVT data generated in this paper can be used to study its potential to condensate blockage and well deliverability. Gas and oil PVT tables are generated for saturated and undersaturated condition, they can be used in reservoir simulation of R reservoir.
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    Petrophysical interpretation in shaly sand formation of a gas field in Tanzania
    (Journal of Petroleum Exploration and Production Technology, 2019-12-13) Mkinga, Oras Joseph; Skogen, Erik; Kleppe, Jon
    An onshore gas field (hereafter called the R field—real name not revealed) is in the southeast coast of Tanzania which includes a Tertiary aged shaly sand formation (sand–shale sequences). The formation was penetrated by an exploration well R–X wherein no core was acquired, and there is no layer-wise published data of the petrophysical properties of the R field in the existing literature, which are essential to reserves estimation and production forecast. In this paper, the layer-wise interpretation of petrophysical properties was undertaken by using wireline logs to obtain parameters to build a reservoir simulation model. The properties extracted include shale volume, total and effective porosities, sand fractions and sand porosity, and water saturation. Shale volume was computed using Clavier equation from gamma ray. Density method was used to calculate total and effective porosities. Thomas–Stieber method was used to determine sand porosity and sand fraction, and water saturation was computed using Poupon–Leveaux model. The statistics of the parameters extracted are presented, where shale volume obtained that varies with zones is between 6 and 54% volume fraction, with both shale laminations and dispersed shale were identified. Total porosity obtained is in a range from 12 to 22%. Sand porosity varies between 15 and 25%, and sand fraction varies between 33 and 93% height fraction. Average water saturation obtained is between 32 and 49% volume fraction.