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Abstract 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.
Grain Size Effects on Residual Oil Saturation
Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Dagogo-Jack, Cyrusba (Nigeria Petroleum Development Company) | Joshua, Dala (Nigeria Petroleum Development Company) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
Abstract 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.
- Asia > China (0.69)
- North America (0.69)
- Africa > Nigeria (0.49)
- Research Report > New Finding (0.56)
- Research Report > Experimental Study (0.56)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- (3 more...)
Comparative Studies of the Performance of ASP Flooding on Core Plugs and Beadspacks
Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin) | Mohammed, Ismaila (Nigeria Petroleum Development Company)
Abstract In this work, we present extensive study of Alkaline-Surfactant-Polymer (ASP) flooding in reduction of residual oil saturation in both core plugs and heterogeneous beads-packs. During the ASP flooding of the core plugs, the effectiveness of the ASP flooding EOR technique on a typical Niger Delta reservoir core and other model cores and the determination of the rock properties that most affect the displacement efficiencies of the processes were analyzed. And in the beads-pack flood test, the potential of the ASP slug for oil recovery, the effect of heterogeneity on the oil recovery efficiency of the process and the investigation of the displacement efficiency of Hengfloc in ASP slug for recovery of Niger Delta oil were all analyzed. Finally, the performance in both was comparatively examined. In the ASP Flooding for beadspack, four different beadspack labeled as W, X, Y and Z were used in the experiment. For core flood test, four different core samples termed A1, B1 T1 and R1 used. For each type of porous media, Brine saturation, oil saturation, water flooding and SP flooding were all carried out on different core samples. The results show that the oil recovery by the imbibition process does not follow a regular pattern. It reveals some complexities in the oil mobilization process and an uneven pattern in the oil recovery due the simulated reservoir heterogeneity. It shows that it's not only the grain size of the reservoir rock but also the arrangement of the grains in the core affect the oil recovery. Water flooding can recover about 70% while ASP flooding can recover between 16 to 19% of the original oil in place from the synthesized heterogeneous beads pack. Bernheimer core gives the best results for ASP EOR flooding operations.
- Asia > China (0.69)
- Africa > Nigeria > Niger Delta (0.46)
- North America > United States > Texas (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Experimental Investigation of the Feasibility of Polymer Flooding in a Shallow Niger Delta Oil Reservoir
Ogienagbon, Adijat (Petroleum Engineering Department, University of Benin) | Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
Abstract 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.
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Africa > Togo > Dahomey Basin (0.99)
- Africa > Nigeria > Dahomey Basin (0.99)
- Africa > Ghana > Dahomey Basin (0.99)
- (5 more...)
Fractional Wettability Effects on Surfactant Flooding for Recovering Light Oil Using Teepol
Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Uzezi, Orivri (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Onuoha, Sean (Petroleum Engineering Department, University of Benin) | Adijat, Ogienagbon (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
Abstract The fractional or mixed wettability of porous media has been recognized as ubiquitous condition in the petroleum literatures. Fractional wettability refers to the fraction of the total pore surface area which is preferentially water or oil-wet. And this wetting condition of a reservoir rock plays a significant role in determining the oil recovery This paper presents laboratory analysis of the effect of wettability alteration on recovery mechanism and the effects of Teepol at different wettability conditions using a glass beads-pack. Oil wet condition was established by the use of kerosene and other fractional wettability conditions were also established. Six experiments were performed. In all the experiments, imbibition, drainage, water flooding, surfactant flooding and polymer flooding were carried out on the porous medium. 0.7PV surfactant solution (teepol) at a concentration of 0.9%wt and 1.1PV polymer solution (gum Arabic) at 5%wt concentration were used. In experiment A, B, C, D, E and Z (control), the porous medium was 100% water wet, 25% water wet and 75% oil wet, 50% water wet and 50% oil wet, 75% water wet and 25% oil wet, 100% oil wet, 100% water wet respectively. The results show that equal percent wettability of both water and oil and complete wettability of either oil or water yield more incremental oil when compared with those of 25% water wet and 75% oil wet condition and 75% water wet and 25% oil wet fractional wettability. Teepol is effective in lowering the oil-water IFT in all porous media with recovery ranging from about 75.5 to 90% of the residual oil saturation (ROS). Experiment C (50-50 fractional wettability) has the highest incremental oil recovery due to grain-to-grain interactive forces while experiment Z has the lowest recovery (about 41% of ROS). This strongly suggests mixed or fractional wettability reservoirs are good candidate of chemical EOR technique. However, even fractions contributions to the mixed wettability by both phases are required for optimum process performance.
- North America > United States (0.46)
- Africa > Nigeria (0.29)
- Research Report > New Finding (0.35)
- Research Report > Experimental Study (0.35)
Cubic Spline and Graphical Techniques for Determining Unsteady State Relative Permeabilities in Field Cores
Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
Abstract 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.
Analysis of ASP Flooding in a Shallow Oil Reservoir in the Niger Delta
Hillary, Attah (Petroleum Engineering Department, University of Benin) | Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
Abstract ASP flooding has been most pertinent among the chemical IOR techniques because it has proven most promising depending on the candidate reservoir. This paper presents the studies of the applicability of ASP flooding in depleted reservoirs in the Niger Delta and reservoirs of similar geologic formation for reasonable incremental oil recovery. The rate of recovery of oil from the reservoir using four different core samples (A, B, T and R) as well as the displacement efficiencies of all four core samples were comparatively analyzed. The fluid flow mechanism of ASP flooding to economically mobilize the residual oil through analyzing production performance was studied. Oil of API gravity of 42.86 degrees and viscosity of 2.5cp and core samples from a Niger delta field were used. 1% wt of NaOH, 0.15% wt of Shell Enordet 0242 and 0.02% wt of Hengfloc 63020 were the alkali, surfactant and polymer used respectively. A sequence of experimental procedure of brine saturation, oil saturation, water flooding and ASP flooding was carried out on the core samples. High pressure core holder, pressure transducer + digital display, digital camera and confining pressure pump were among the instruments used to accomplish the studies. The results show potential to recover significant additional oil by ASP flood after the 10% recovery factor common to a large number of conventional oil reservoirs in the Niger Delta to date. The reservoir rock shows favourable response to the ASP flooding mechanism, recovering a reasonable percentage of the OOIP which is definitely handy for resolving the declining marginal fields in the Niger delta.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.61)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- (3 more...)
Experimental Approach to CEOR Optimization in Niger Delta
Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Adijat, Ogienagbon (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin) | Joshua, Dala (Petroleum Engineering Department, University of Benin)
Abstract 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.
- Asia (0.93)
- Africa > Nigeria > Niger Delta (0.82)
- Research Report > Experimental Study (0.68)
- Research Report > New Finding (0.48)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)