The purpose of this research work is to comparatively study the oil recovery factor from two major aquifer geometry (Bottom and Edge water aquifer) using water aquifer model owing to the fact that most if not every reservoir is bounded by a water aquifer with relative size content (Most Large). These aquifers are pivotal in oil recovery factor (percent%), Cumulative oil produced (MMSTB) as well as overall reservoir performance the methodology utilized in this study involves; Identification of appropriate influx models were utilized for aquifer characterization. The characterizes of the Niger Delta reservoir aquifer considered include aquifer permeability, aquifer porosity etc. Estimation of aquifer properties is achieved by using regressed method in Material Balance Software (MBAL). This approach involves History Matching of average reservoir pressure with computed pressure of the reservoir utilizing production data and PVT data. The computed pressure from model is history matched by regressing most uncertain parameters in aquifer such as aquifer size, permeability, and porosity. Historic production data was imputed into the MBAL Tank Model, the production data was matched with the model simulation by regressing on rock and fluid parameters with high uncertainty. The match parameters were recorded as the base parameter and other sensitivity on aquifer parameters using the Fetkovich model for the bottom and edge water drive. The average percentage increase in oil cumulative volume was 0.40% in fovour of bottom water drive. Further sensitivity on cumulative oil recovered showed the increase in reservoir size with increasing aquifer volumes increases oil production exponentially in bottom water drive whereas edge water drive increased linearly. Aquifer volume, aquifer permeability showed linear relationship with bottom and edge water drive.

The purpose of this research work is to comparatively study the oil recovery factor from two major aquifer geometry (Bottom and Edge water aquifer) using water aquifer model owing to the fact that most if not every reservoir is bounded by a water aquifer with relative size content (Most Large). These aquifers are pivotal in oil recovery factor (percent%), Cumulative oil produced (MMSTB) as well as overall reservoir performance the methodology utilized in this study involves; Identification of appropriate influx models were utilized for aquifer characterization. The characterizes of the Niger Delta reservoir aquifer considered include aquifer permeability, aquifer porosity etc. Estimation of aquifer properties is achieved by using regressed method in Material Balance Software (MBAL). This approach involves History Matching of average reservoir pressure with computed pressure of the reservoir utilizing production data and PVT data. The computed pressure from model is history matched by regressing most uncertain parameters in aquifer such as aquifer size, permeability, and porosity. Historic production data was imputed into the MBAL Tank Model, the production data was matched with the model simulation by regressing on rock and fluid parameters with high uncertainty. The match parameters were recorded as the base parameter and other sensitivity on aquifer parameters using the Fetkovich model for the bottom and edge water drive. The average percentage increase in oil cumulative volume was 0.40% in fovour of bottom water drive. Further sensitivity on cumulative oil recovered showed the increase in reservoir size with increasing aquifer volumes increases oil production exponentially in bottom water drive whereas edge water drive increased linearly. Aquifer volume, aquifer permeability showed linear relationship with bottom and edge water drive.

Unconventional oil reserve estimate in Nigeria which is at an average of 42 billion barrels of hydrocarbon deposits, surpasses the proven reserve of 37.2 billion barrels of conventional oil reservoirs. With these statistics, the need to evaluate the prospects of production from these unconventional reservoir systems becomes a subject of interest. In this study, a thermal approach towards the recovery of a Niger Delta heavy crude oil was conducted by the viscosity reduction mechanism via hot water injection. Fluid characterization via laboratory tests revealed that the Niger Delta retrieved heavy crude sample had a viscosity 17.80 cp,13.24oAPI and a density of 0.997.6 g/cc. This sample was subjected to a series of recovery processes with hot water temperature ranging from 75 OC to 100 OC at an interval of 5oC, using a locally constructed apparatus. It was used to simulate a reservoir bulk volume of 30 litres and 8.871 liters pore volume having fluid saturations of 20% formation brine. The heavy crude viscosities were found to be in the magnitude of 1.95cp to 0.87 cp for injected hot water of 75 OC to 100 OC after post recovery tests. Temperature losses to the rock matrix of a heavy crude reservoirs and optimum injection temperatures for a known reservoir bulk volume were also established via experimental processes. The validity of assertion that hot water injection can considerably alter flow properties of heavy oils was experimentally confirmed upon comparing with a convention al water injection process.

Microbial enhanced oil recovery application (MEOR) is a potentially attractive way to recover additional oil from a reservoir. This study reveals the ability of microorganisms for mobilization and displacement of residual oil in sand pack cores by the action of produced biosurfactant. Isolates of hydrocarbonutilizing bacteria were identified as pseudomonas, Bascillus, Citrobacter and Escherichia, using microscopic examination and biochemical tests. Three of the listed microbes were confirmed to be potential biosurfactantproducing microbes by testing the spent culture filtrate of the isolates. Pseudomonas and Escherichia were observed to produce biosurfactants only on nutrient broth, which was observed to emulsify hydrocarbons. The flooding experiment also showed that primary recovery accounts for about 25% and that of secondary oil recovery (brine chase) approximates 20% of original oil in place. The maximum oil recovery achieved by tertiary oil recovery (MEOR) using biosurfactants was approximately 50% OOIP. These biochemical tests conclusively reveal that biosurfactant slugs are technically feasible for maximizing oil recovery by reducing interfacial tension for improved mobilization of hydrocarbons.

Unconventional oil reserve estimate in Nigeria which is at an average of 42 billion barrels of hydrocarbon deposits, surpasses the proven reserve of 37.2 billion barrels of conventional oil reservoirs. With these statistics, the need to evaluate the prospects of production from these unconventional reservoir systems becomes a subject of interest. In this study, a thermal approach towards the recovery of a Niger Delta heavy crude oil was conducted by the viscosity reduction mechanism via hot water injection. Fluid characterization via laboratory tests revealed that the Niger Delta retrieved heavy crude sample had a viscosity 17.80 cp,13.24oAPI and a density of 0.997.6 g/cc. This sample was subjected to a series of recovery processes with hot water temperature ranging from 75 OC to 100 OC at an interval of 5oC, using a locally constructed apparatus. It was used to simulate a reservoir bulk volume of 30 litres and 8.871 liters pore volume having fluid saturations of 20% formation brine. The heavy crude viscosities were found to be in the magnitude of 1.95cp to 0.87 cp for injected hot water of 75 OC to 100 OC after post recovery tests. Temperature losses to the rock matrix of a heavy crude reservoirs and optimum injection temperatures for a known reservoir bulk volume were also established via experimental processes. The validity of assertion that hot water injection can considerably alter flow properties of heavy oils was experimentally confirmed upon comparing with a convention al water injection process.