http://repository.aust.edu.ng/xmlui/handle/123456789/369 This collection contains theses of Petroleum Engineering Students from 2016-2022 Tue, 07 Apr 2026 11:38:01 GMT 2026-04-07T11:38:01Z http://repository.aust.edu.ng/xmlui/handle/123456789/5161 Pressure Transient Behavior in Horizontal Wells and Hydraulically Fractured Vertical Wells With Non-Newtonian Fluid Flow in Porus Media: Non-Composite and Composite Reservoirs Ologun, Mojeed Olawale Two fluid regions are usually created during either water or polymer injection into an oil reservoir for enhanced oil recovery. The two fluid regions create a composite reservoir system that requires analytical solution that can be used to evaluate the injection performance. This study present a 2D solution for non-Newtonian fluid in the inner Zone coupled with infinite boundary in the outer Zone; using power law model. The outer Zone fluid can either be Newtonian or non-Newtonian. Moreover, the mathematical model is formulated such that either Zone can be with non-Newtonian power law fluid or Newtonian fluid. The infinite conductivity fractured solution obtained was compared with the ones obtained using the radial line source solution that had already been developed in the literatures and a perfect match was obtained. An application was made to three examples that have been presented in a previous work and satisfactory results were obtained. The dimensionless pressure drops during the early linear flow regime for all values of flow indices are the same, but with deviation during radial flow regime. Moreover, the existing work is limited to radial model in a vertical well, infinite conductivity hydraulic fracture, software simulation model and numerical model. Up to date, there has been no analytical work presented for horizontal well using power law model. Power law model best characterizes non-Newtonian rheological properties and the fluid flow in porous media. Today, horizontal well is widely being used in the exploitation of oil and gas in the industry; either as a producer or an injector. A reservoir where the flow of injected polymer solution during enhanced oil recovery and high viscosity crude oil exhibit non-Newtonian behavior, is better characterized with pressure transient with power law model. This fact has been established. This study also presents a 3-D power law model for analyzing pressure transient behavior in a reservoir with fluid flow that exhibits non-Newtonian behavior. The solution provided is semi-analytical and numerically inverted using Stehfest Algorithm. A step-by-step analytical procedure for analyzing each flow regime is developed. In order to validate the 3-D model, type curves were developed and matched with data provided from simulator in previous work. The step-by-step procedure was used to analyze an eclipse simulated data. There was consistency in the results that validated the analytical mathematical model. The 3-D analytical model developed is also applicable to composite reservoir with two distinct zones due to fluid and rock properties. The flow behavior index in both zones can either be 1.0 or less than 1.0. This is unique to this study. Furthermore, finite conductivity hydraulic fracture mathematically gives the general solution for transient pressure behavior in a fractured well. This study presents a semi-analytical solution and a numerical method which can be used to evaluate the performance of an injection operation in a finite conductivity fracture either in a homogeneous reservoir or a naturally fractured reservoir. The solution obtained was subjected to a validation process by comparing the estimated dimensionless wellbore pressure obtained with that of a previous work where numerical method was used. A good match was obtained. An application was also made to field examples that have been presented in a previous work and satisfactory results were obtained. Main Thesis Fri, 05 Jan 2024 00:00:00 GMT http://repository.aust.edu.ng/xmlui/handle/123456789/5161 2024-01-05T00:00:00Z http://repository.aust.edu.ng/xmlui/handle/123456789/5090 Integrated Modelling and Optimization of Options for Developing Thin Oil Rim Reservoirs: Niger Delta Case Study Aladeitan, Yetunde Mariam The goal of an oil field development project is to accelerate the hydrocarbon production and maximize recovery at the lowest cost. Optimizing the production of oil from thin oil rim reservoirs poses a major challenge in the oil and gas industry because of the water and gas coning tendencies which limit the ultimate recovery from such reservoirs. Development of oil rims generally requires a lengthy study to unravel the complex interplay of the subsurface uncertainties and to determine technical feasibility, development concept and economic attractiveness. Simulations and experimental methods coupled with simple analytical solutions or correlations are typically used to identify the oil rate that minimizes coning and maximizes recovery. This research aims to optimize oil recovery from oil rims by generating models to be used to forecast production rates and increase the ultimate recovery over a range of uncertainties. In this work, a surrogate simulation model is developed to analyze oil rim dynamics and evaluate the impact of a range of subsurface uncertainties on the oil and gas recovery. Alternate development strategies have been considered, and the method of experimental design was used to obtain correlations for each development strategy. The lessons learned from the generic model were incorporated into a systematic study of an integrated reservoir management plan for developing an oil rim reservoir in the Niger Delta. Seven reservoir development strategies are evaluated using numerical reservoir simulation; and the optimum production strategy is selected. The evaluation of the best strategy includes optimization of well placement and economic analysis using the cumulative oil and gas recovery from the various development strategies. In the economic analysis several profitability indices such as net-present value, internal rate of return, and discounted payout period were utilized to identify the optimum development strategies. The results show that well placement has a significant impact on water and gas coning and on oil recovery. It is concluded that the development of thin oil rim reservoir requires an integrated reservoir management plan. Proper reservoir management is achieved when the reservoir producibility factors, operational constraints and economics of the project are considered in the field development planning. Sat, 12 Sep 2020 00:00:00 GMT http://repository.aust.edu.ng/xmlui/handle/123456789/5090 2020-09-12T00:00:00Z http://repository.aust.edu.ng/xmlui/handle/123456789/5043 Upstream Petroleum Industry Performance Evaluation using Data Envelopment Analytic Approach Idowu, Adekunle Joseph Nigeria ranks among the top ten petroleum producers in the world with over eighty petroleum Investors in its upstream sector. This creates an enormous challenge for the upstream institutions’ managers especially in the evaluation of technical performance of the sector. One major problem is that there is hardly any quantitative empirical information on technical efficiency of the sector for effective performance evaluation and strategic policy formulation. It is this identified knowledge and information gap that this study aimed to fulfill by estimating the needed relative technical efficiency for each of the 32 selected upstream industry operators in Nigeria. The study adopts an output-oriented data envelopment analysis framework considering a constant return to scale, variable return to scale and non-increasing return to scale. Consequently, an economic analysis was carried out using a panel data econometrics model to establish the determinants of technical efficiency in the Nigerian upstream sector. The results of the analysis revealed decreasing trends in the upstream sector operators’ technical efficiencies from 2010 to 2016. Additionally, the panel data econometrics model revealed that four of the selected independent variables were statistically significant determinants of the upstream technical efficiency in Nigeria within the period of the study. In conclusion, this study recommends strategic policies towards minimizing bureaucracies and enabling new efficiency-oriented ideas for operators on decreasing return to scale frontier. It also recommends the formation of alliance among the operators on increasing return to scale frontier to boost internal growth and unlock significant values. As regards the six operators on a constant return to scale production frontier, it is specifically recommended that they should embark on serious reserves growth’s strategy to increase their reserves base. Sun, 23 Jun 2019 00:00:00 GMT http://repository.aust.edu.ng/xmlui/handle/123456789/5043 2019-06-23T00:00:00Z http://repository.aust.edu.ng/xmlui/handle/123456789/5041 Genetic Units Based Reservoir Characterization using a Normalized Pore Throat Radius for the Clastic System: Niger Delta as Field Case Study Onuh, Haruna Monday Globally, 30–50% of hydrocarbon volumes in silici-clastic reservoirs are contained within the thin-bedded pay. In the Niger Delta deep water assets, over 30% of in-place volumes are found within the complex turbidites. The presence of multi-pore architecture within such facies makes their description from petrophysics very complex. With the quest for hydrocarbon prospects in frontier deep water settings characterized by such complex rock fabric, detailed reservoir characterization is essential for accurate field management and production optimization. The focus of this work is to characterize complex reservoir pore systems at core scale based on genetic reservoir unit averages and to provide improved models for petrophysical evaluation using a normalized pore throat radius approach for clastic reservoirs. New methods are presented for modelling permeability in rocks with multimodal pore throat size distributions using Niger Delta field as case study. The statistical significance of the coefficients in the proposed relationships for various genetic reservoir units was verified using α-level of 0.05; and the results indicate that the proposed model is very unlikely to have occurred by chance. Two methodologies are presented for upscaling from core plug to log scale–genetic unit averages of pseudo normalized pore throat radius as input parameter to the proposed model. This study also presents improved methodology for generating capillary pressures from NMR T2 relaxation time using a genetic unit based averages of the kappa scaling parameter proposed by Volokitin et al. The improved methodology is also applicable to conventional geophysical logs for estimating capillary pressure in the absence of NMR T2 data. Comparative analyses indicate that the proposed methodology is an excellent improvement over existing methods (e.g., Reservoir Quality Index, Leverett J-Function, Stratigraphic Modified Lorenz Plot) for characterizing hydraulic flow units. Additionally, efficiency of the proposed methodology is demonstrated by comparison of estimated permeabilities versus core permeabilities from four depobelts in the Niger Delta. Permeabilities were derived from existing methodologies including Genetic Unit Averages of FZI’s, Neural Network Permeability, NMR based Schlumberger Doll Research (SDR) and Coates correlations. It is concluded that the proposed methodology is a superior and practical tool for reservoir characterization. Mon, 12 Dec 2016 00:00:00 GMT http://repository.aust.edu.ng/xmlui/handle/123456789/5041 2016-12-12T00:00:00Z