Petroleum Engineering

Permanent URI for this communityhttps://repository.ui.edu.ng/handle/123456789/563

Browse

Author: search.filters.author.Akpabio, U. J.Has files: Yes

Search Results

Now showing 1 - 2 of 2
  • Thumbnail Image
    Item
    Determination of some petrophysical properties of reservoir rocks in the Niger Delta
    (2015) Akintola, A. S.; Akpabio, U. J.; Nduamaka, C. F.
    In formation evaluation, the knowledge of porosity, permeability and fluids saturation are very important in the determination of the hydrocarbon in place. These petro physical properties are necessary to understand the nature of the reservoir and help for proper field development planning. This was aimed at determining the petro physical properties (pore volume, bulk volume, grain volume, permeability and fluid saturation) of a reservoir from core plugs. A total of ten core plugs were used in this work. Archimedes immersion method was used in the determination of the bulk volume. Liquid saturation method was used in the determination of the porosity. The Dean-Stark extraction method was used in the determination of fluid saturation. From the results obtained in the core analysis, the sandstone reservoir has an average porosity of 14.9±5.1%, very good permeability with an average value of 349.77±0.3 mD and a very large water saturation value of 82±0.4%. Consequently the hydrocarbon saturation is approximately 18%. This implies that the formation is not commercially viable to develop based on the hydrocarbon saturation. The study shows that experimental work is one of the valid tools for making informed decisions on the development of a field in the petroleum industry and highlights the importance of the basic petrophysical properties in reservoir management.
  • Thumbnail Image
    Item
    Pressure gradient prediction of multiphase flow in pipes
    (2014) Akintola, A. S.; Akpabio, U. J.; Onuegbu, M.
    Pressure traverse in multiphase flow differs from single phase flow due to the differential flow rates of the different phases. Correlations developed to predict multiphase flow pressure traverse are mostly for vertical wells but Beggs and Brill model is one of the few models that is used for inclined pipes. The work seeks to show the improvement in the modification of the model. This project is based on studies carried out on multiphase fluid flow in pipes of any inclination using the Beggs and Brill flow model as the focus. Two cases were considered, the liquid holdup correction and Gas Liquid Ratio (GLR) variations in which the Beggs and Brill and Beggs and Brill Traverse models were compared. Due to the empirical nature of the Beggs and Brill model, pressure gradient predictions are far from accurate when compared with measured data in the field. This project seeks to reduce the error margin between predicted pressure gradient values and measured data. It was observed that for the same reservoir, fluid, and pipe properties, the Beggs and Brill Traverse Model is a better prediction tool than the Beggs and Brill model. Prediction errors were seen to increase with increase in length for GLR above 400 scf/stb while they were more accurate for pipes between 12,000 and 17,000 ft and pressures between 3,000 and 4,500 psi. However, the Beggs and Brill Traverse Model, is limited by the choice of correlations used in the computation of fluid properties.