Recovery factor of an oil reservoir is paramount for accurate reserves estimation and field development planning. It is usually estimated using expensive simulation or experimental studies. However, most published models account for only primary recovery. This study is therefore designed to develop a correlation model that can estimate recovery factor under both primary and secondary recovery from oil reservoirs in the Niger Delta having water and depletion drive mechanisms. For this study, the models for recovery factor were established using statistical correlation of data collected from 136 oil reservoirs in the Niger Delta. A sensitivity analysis was performed on different parameters affecting recovery factor of water and depletion drive reservoirs. The results obtained were compared to other published models. The results show that for both water and solution gas drive reservoirs; oil viscosity and residual oil saturation do have a strong correlation with recovery factor, while pressure, API gravity and gas oil ratio do have a strong correlation with recovery factor only in solution gas drive reservoirs. Results also show that no statistical correlation exists between formation volume factor, reservoir thickness, porosity, permeability, initial water saturation, temperature, water viscosity and recovery factor. The novelty of the recovery factor models is its ability to estimate secondary recovery factor for oil reservoirs that have been subjected to water injection. However, the models developed in this study should be valid also to oil reservoirs in other regions having similar geological characteristics.

The goal of this paper is the comparative analysis of three injection fluid options: Surfactant-enhanced-Water (SeW), Water Alternating Gas (WAG) and Surfactant-enhanced-WAG (SeWAG). The objectives are to identify the best option with the highest oil and gas displacement efficiency and the best development strategy for optimum recoveries in concurrent development of an oil rim reservoir. The Eclipse simulator was used because of its robust ability in simulating various injection options of an oil rim reservoir in a green field. Four scenarios (base case/no injection, SeW, WAG and SeWAG injections) were simulated under the same conditions to determine injection option with the best displacement efficiency and recoveries of oil and gas. Statistical analysis using Pareto chart was performed for proper identification of the option with the best recoveries. The result showed that SeWAG injection ratio 1:4:2 and injection cycles 56 gave the best recoveries for oil and gas with displacement efficiency of 0.08 and 0.332 respectively, followed by SeW injection with values of 0.073 and 0.331 respectively, while WAG has the least performance. On the Pareto chart, SeWAG simulation result has the highest percentage among the options with the best recoveries of 3.35 MMSTB oil and 16.05 BSCF gas, which is 12.53% and 16.12% of oil and gas in place after 9.6% of oil and 15.1% of gas have been recovered by natural depletion. Hence, this study has shown that two stages of development strategy (combination of natural depletion and SeWAG injection when the reservoir pressure is depleted) give cumulative effect for optimal recoveries in concurrent development of oil rim reservoir.

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Recovery factor for gas reservoirs are highly dependent on factors such as initial reservoir pressure, abandonment pressure and the type of reservoir drive mechanism. Producing gas reservoirs with active water drive mechanism possess a lot of challenge to the field operator since optimum production of gas is dependent on reduced pressure. Material balance model was used to derive basic reservoir and production parameters thereafter Excel was used to simulate the parameters for both conventional and co-production scenarios using a field data from the Niger Delta Basin. The reservoir contains three producing wells with conventional technique, while co-production has three wells, producing gas from the up-dip and one well producing water from the down-dip. The simulated results show that gas production rate from the three wells changed with respect to the production strategies. Under conventional, gas production rate from the three wells was at a constant rate of 19MMSCF/D for a long period of time. However, under co-production technique, gas production rate was at a constant rate of 38MMSCF/D for a short period of time. Under conventional method, 231.85BCF of gas was recovered from 356.713BCF of gas initially-in-place with recovery factor of 65% until water cut set-in at an abandonment pressure of 2000 psia. However, under co-production technique, the simulated result shows that there was an optimum recovery of gas of up to 92% recovery which is 27% above the conventional technique and the reservoir pressure was depleted to 1000 psia before water cut set-in.

This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.