In order to improve the efficiency of the enhanced oil recovery process, researchers have come up with different methods such as mobility control, chemical, miscible, thermal and other processes such as microbial. In chemical flooding for example, alkaline, polymer, surfactant, surfactant polymer (SP) and alkaline surfactant polymer (ASP) have all been employed in the quest for better efficiency. However, grain size effect on the recovery system during these tertiary recovery techniques has received less attention over the years. This paper presents evaluation of the effects of grain size on residual oil saturation (ROS) from experimental studies of oil recovery potentials of a formulated ASP slug in synthetic porous media. 1% weight of sodium hydroxide (NaOH), 0.15% weight of shell enordet 0242 supplied by shell research centre and 0.02% weight of hengfloc 63020 were used as alkali, surfactant and polymer respectively. Ranges of core grain sizes of 0.063 to 0.090, 0.106 to 0.150, 0.150 to 0.212, 0.212 0.300 and 0.425 to 0.600 micron were considered in five different experiments performed. Each of the experiment was accomplished by a procedural sequence of brine saturation, oil saturation, water flooding and ASP flooding. The results show that the porosity of the synthesized core increases with decreasing grain size from 37.2% to 43.74% for a range of 0.600 micron to 0.063 micron of sizes. The permeability of the synthetic core decreases from 2309 millidarcy to 669 millidarcy as the grain size decreases from 0.600 micron to 0.063 micron. Pressure drop across the beads pack increases from 0.294 psi to 1.015 psi as the grain size reduces. The oil recovery by an immiscible fluid through the beads pack increases as the pore throat get smaller or the grain size reduces. The volume of ROS after flooding reduces as grain size reduces.

The global oil price as well as Nigeria’s current reserve is on a continuous alarming decline. With the increasing finding cost of new wells and demand for energy, improving oil recovery from existing wells becomes highly pertinent. Generally, waterflooding leaves approximately two thirds of the OIIP as un-swept or residual oil resulting to a low recovery factor. The improvement of recovery factor is one of the identified five Research & Development (R&D) grand challenges or upstream business needs highlighted by the SPE R & D committee. Enhanced Oil recovery (EOR) methods provide an avenue to Petroleum engineers to unravel this challenge. In lieu of this, we investigated the feasibility of improving recovery with polymer flooding technique in the Niger Delta region of the Sub-Sahara Africa. A sequence of brine saturation, oil saturation, water flooding and polymer flooding was carried out on four different cores (core A, B, T & R). Core A & B are ROBU cores (specially manufactured synthetic cores), T is Bentheimer core and while R is a reservoir rock core sample from a shallow central Onshore Niger Delta reservoir. The results show comparative responsiveness of oil recovery to polymer flooding by the various core samples. Core samples T & R are good candidates for polymer flooding having produced 21.28% & 13.33% after polymer flooding. Model Bentheimer rock sample (T) which has close petro-physical properties to that of the case studied reservoir has the highest displacement efficiency of 52.63%. The core flood analysis demonstrated that polymer flooding could improve oil recovery within the Central Onshore reservoir of the Niger Delta.

This paper presents laboratory analysis of optimum surfactant concentration needed for Niger delta oil recovery in Nigeria. Eight experiments were carried out on a crude sample from the field with different surfactant concentrations to water (0.1%, 0.3%, 0.5%, 0.7%, 0.9%, 1.1%, 1.3%, 1.5% surfactant) using glass beads to simulate the actual field process. Brine saturation, oil saturation, water flooding, surfactant flooding and polymer flooding were done for each of the eight experiments performed and the resulting recoveries were analysed and compared. Then, the optimum surfactant concentration was identified. The results show that 0.9% surfactant concentration is the optimum concentration needed for flooding in this field. Any concentration more than or less than 0.9% would yield less than the optimum recovery. It would be uneconomical to maintain a surfactant concentration higher than 0.9%. Recovery does not necessarily increase with increasing surfactant concentration in the mobilising slug. The field operators in this field are hereby advised to consider 0.9% surfactant concentration.

The Johnson, Bossler and Neumann (JBN) method is the industry standard for measuring relative permeabilities from field cores. Mitigating the numerical errors resulting from the numerical differentiation required by the method has been an area of interest over the years. There have been several modifications of this technique by many researchers in order to improve the results. Some of the researchers have used curve fitting and graphical approach. However, till date, the application of a numerical modeling technique to do the necessary numerical differentiation of the data required by the JBN method for improved results is yet to be established. This paper presents the application of cubic spline numerical modeling technique (CSNMT) on JBN method. Production data from field cores were used. The JBN technique was initiated procedurally. The necessary numerical differentiation of the production data required by the JBN method was done with cubic spline numerical modeling technique (CSNMT). Tridiagonal system of equations was formed and resolved. Different and continuous equations (polynomials) were derived for the contiguous intervals and then differentiated accordingly. The procedure was then accomplished. The technique shows good results which are close to those obtained when the numerical differentiation is done the traditional way, using an expression for an unequally spaced data gotten from the numerical differentiation of a second-order langrage interpolating polynomial for three data points. However, because of the oscillations induced and the difficulty in handling higher order polynomials numerically which leads to the use of second-order langrage interpolating polynomial instead of a polynomial of order one minus the number of the data points required, the results from the use of CSNMT are more reliable. In addition, the profiles of the production data are modeled in CSNMT. The reduction in the overall numerical error was reflected by the differences in the relative permeability values obtained by both approaches.

Relative permeability is one of the key factors in reservoir engineering calculations to simulate multiphase behavior in porous media. The relative permeabilities calculated from established models do not perfectly characterize the reservoir without a known trend or history. This necessitates the need to use a reliable and globally accepted technique based on Niger Delta field production data for calculating relative permeabilities from the fields so that the models derived from the relative permeability curves could be tamed and domesticated in the region for better reservoir characterization and evaluation. The Johnson, Bossler and Neumann (JBN) method is the industry standard for measuring relative permeabilities from field cores. In order to eliminate the need of using numerical differentiation, and therefore reduce the overall numerical error in this method, a graphical technique was proposed and implemented during late 70s. However, with splines, the numerical differentiations are still done but with improved results. The current study presents the results from the comparative analysis of two approaches employed to avoid the traditional numerical differentiation required by the JBN method. Production data from field cores in the Niger Delta were used. The graphical method and cubic spline numerical modeling were both used to calculate the individual relative permeabilities from the pressure/production history of the displacements. the results were analyzed and compared. The results of both methods show a very good match over a fairly small saturation range and also differ. However, cubic spline results are closer to the traditional numerical differentiation results because is a modeling approach in which the numerical differentiation is incorporated with improved accuracy.

As important as Chemical Enhanced Oil Recovery (CEOR) methods are to generating additional oil, the effectiveness of the CEOR method used is dependent on its design, rock-fluid and fluid-fluid interaction. Therefore this paper presents the outcome of experimental works to formulate an optimum surfactant Polymer slug for tertiary oil recovery (TOR) of the Niger Delta oil. Firstly, the displacement efficiency of Hengfloc 63020, a polymer was tested four flood experiments for Niger delta oil. Also the rheological properties for a wide range of concentrations were measured. Secondly, Teepol was screened in the pack flood test at different concentrations. Thirdly, the optimum surfactant concentration and optimum surfactant injection rate were investigated. The fourth set of experiments investigated the effect of flood process design in a three beads pack flood tests to select an appropriate scheme. Using the best flood scheme, the formulated SP slug was then used to recover oils of viscosity range from 3.5cp to 140cp. Advanced mathematical methods were used to analyze and model the experimental results. The experimental results show that better displacement efficiency can be achieved within a range of polymer concentration for oil. Also the performance of SP flood program is dependent on the right slug formulation, the injection rate and the overall project design. From the analysis of the cores used in the experiment, a fair idea of the efficiency of surfactant –polymer flooding in reservoirs with similar properties of the cores used in the experiment can be inferred.

Based on Welge's solution of the flow equation, a method (JBN technique) to calculate the individual phase relative permeabilities from displacement data was developed for the first time in 1959. It's the most commonly used data reduction method for obtaining relative permeability relationships from unsteady state data. Similar to the Welge method, differentiation of data is required and negligible capillary end effects are assumed when using the JBN method. To apply the JBN method, information on pore volumes of fluids injected and produced, the pressure drop across the porous medium and fluid viscosities is needed. This method generally gives relative permeabilities over a fairly small saturation range, which varies depending on the relative mobilities of the flowing fluids. In order to improve the results of this method, many researchers have come up with different techniques in their JBN analysis including the cubic spline numerical modeling technique (CSNMT) discussed in this research. This paper presents relative permeability data obtained from comparative analysis of the JBN method with different approaches. The differentials of second order Lagrange interpolating polynomial and cubic spline numerical modeling technique (CSNMT) were all considered in the JBN analysis. The relative permeability curves were then analyzed and the best method was chosen. The results of all the different methods employed in the JBN analysis do not match perfectly throughout the entire saturation range. The errors in the use of the differentials of second order Lagrange interpolating polynomial on more than three data point are very substantial. The results obtained from the application of cubic splines are more representative of the relative permeabilities from the field cores.

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