Following on from the work by Tang and Morrow in 1998, enormous progress has been made in the development of low salinity water flooding for improved oil recovery, (IOR). This paper has assessed the applicability of modified salinity as an IOR scheme in the Niger Delta. A laboratory approach which entailed the use of crude oil, brine and core plugs from fields X and Z located in the Niger Delta was adopted. Several options were assessed: progressive dilution of the injected brine, variation of concentration of divalent cations in the injection fluid, high salinity flooding followed by low salinity flooding (HSF, LSF) and variation of low salinity slug size. The results obtained are very promising as additional recoveries in the order of +5% to 21% were obtained from this work. Based on the promising results of this on-going research, recommendations on future improvements were also outlined.

Production of bitumen from tar sands requires heating the reservoir to several degrees of magnitude to reduce the viscosity of the bitumen. Proper characterization of viscosity property of this fluid is necessary for the designing and optimization of recovery methods. In this work, tar sand samples were collected from different locations in the Ore axis of Ondo state. Bitumen were extracted from the tar sands. The effect of temperature on the viscosity of each sample were measured using an NDJ-8S digital viscometer at temperature ranging from 122-374°F. Viscosity behaviour were different from location to location and they typically reduced as temperature increased. Viscosity measurement varied from 876,000cp – 5,200cp as temperature increased from 122-374°F. Some samples showed higher viscosity profile than other sample. Therefore, higher temperature and energy requirement is needed for the recovery process of these Nigeria Reservoirs.

Gas condensate banking accumulated near the wellbore occurs when the bottomhole pressure becomes less than the dew point pressure, allowing the liquid fraction to condense out of the gas phase. Once the accumulation near the wellbore is higher than critical condensate saturation, the liquid phase becomes mobile with the gas phase, affecting well deliverability and making it difficult to estimate gas and condensate flow rate from the reservoir due to two phase flow of fluid. This paper presents an analytical model that evaluates the well deliverability from the reservoir. The concept of two phases Pseudo-pressure is used in the interpretation and evaluation of well deliverability from the gas condensate reservoir. The model considers non-Darcy flow effects and capillary effects. The model is applied to a live field case study of a Niger Delta gas condensate reservoir to determine well deliverability. Gas and liquid production profile from the model showed 95% accuracy when compared with compositional simulation model. This model is encoded into a spreadsheet program using python to calculate well deliverability parameters.

One important process for revitalization and optimisation of mature reservoirs is secondary recovery by waterflood. However, some engineers do not understand the science and, consequently, without proper plan lose millions of dollars of investment because they target reservoirs for waterflood secondary process which do not possess appropriate characters. This paper presents screening criteria for waterflood projects in a matured field in the Niger Delta region of Nigeria. Data set for a field X in the Niger delata was simulated. Sensitivity analysis was carried using different scenario and their results were reported. Six parameters which can be used to screen reservoirs for water flood potential were proposed in this paper.The result of the evaluation showed that waterflood are best applicable for reservoirs with residual oil saturation of less that 33%,gas saturation of greater than 15% and API gravity of less than 30cP.

No abstract