Chemical & Petroleum Engineering-Scholarly Publications

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Browsing Chemical & Petroleum Engineering-Scholarly Publications by Author "Adeyanju, O."

Now showing 1 - 9 of 9
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    Open Access
    Experimental Studies of Sand Production from Unconsolidated Sandstone Petroleum Reservoirs in Niger-Delta
    (Faculty of Engineering, University of Nigeria, Nsukka, 2011-06) Adeyanju, O.; Olafuyi, O.
    Production of sand during oil and gas exploration causes severe operational problem for oil and gas explorers especially companies producing from unconsolidated formations. Most reservoirs in the Niger-Delta fall in this category. Production oil and gas from such reservoirs has been limited by rate-dependent sand production and fines migration which resulted in near wellbore formation plugging. To prevent this occurrence, controlling the oil and gas flow rate will be of high importance to the oil and gas companies especially the producers operating in the Niger Delta. A physical model which has capacity for both consolidated and unconsolidated samples has been used to simulate the effect of flow rates, confining pressure, pressure drawdown and fluid viscosity on sand production in the Niger Delta. The model was also used to determine the ability of using the flow rate to control the production of sand. Sand sample from an unconsolidated reservoir in the Niger Delta was used in the model. Light and heavy crude oil with laboratory simulated brine was used as fluids as well. Results from the studies showed that the sand production increased as the following parameters; the flow rates, the confining pressure, the drawdown and the viscosity of the formation fluid are increased. The results also indicates that high sand-free flow rates can be achieved if the sand formation is mechanically confined (compacted). Further investigation revealed that sand production can be controlled by managing the flow rate alone when light oil was used while it is impossible to control sand production by managing the flow rate alone when heavy oil was used.
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    Open Access
    Experimental Study of Viscosity as a Criterion for Determination of Onset Asphaltene Flocculation in Nigeria,s Crude
    (Petroleum and Coal publishers, 2015-07) Adeyanju, O.; Adeosun, T.; Obisanya, A.
    Asphaltene are heavy hydrocarbon molecules that exist naturally in petroleum reservoir fluids. Asphal-tene precipitation may occur during pressure depletion or during gas injection process for Improved Oil Recovery (IOR). It is an important problem during oil production because it can result in formation damage and plugging of wellbore and surface facilities. In this experimental study, the rheological behaviors of Nigeria’s crude oil sample were reported. This research used a typical Nigeria’s oil sample to generate information on the asphaltene deposition tendency of a heavy crude oil sample using the standardized test as described by American Society for Testing and Material Method (ASTM) D-3279-90. The results obtained show that the amount of asphaltene precipitated out of a crude sample is dependent upon the type of solvent used. Generally, the lower the number of carbon atoms in the solvent, the greater the amount of asphaltene precipitated. Also contrary to the general belief, that since Nigeria’s crude is known for its low asphaltene content, the nation’s oil industry needs not to take the asphaltene precipitation effect into consideration, it was observed that asphaltene concentration as low as 1% (percentage weight) is enough to change the rheological behavior of crude samples from Newtonian to Non-newtonian flow. It was also observed that the flocculation and not precipitation of asphaltene was responsible for the change in the rheological behavior. These changes in rheological properties can lead to reduction in the rate of crude oil flow in a petroleum reservoir, and hence reduced productivity.
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    Open Access
    Experimental Study of Wax Deposition in a Single Phase Sub-Cooled Pipelines
    (Nova Science Publishers, Inc., 2013-08) Adeyanju, O.; Oyekunle, L.
    The ability to determine the severity of wax deposition is an extremely important issue, particularly in the design and development of deepwater oilfields. Though much progress has been made in the last decades to better the understanding of this complex process, yet the ability to accurately account for all the factors that affect wax deposition are currently not in existence in the wax simulators used presently in the industries. In this study an experimental methodology constructed to simulate wax deposition process was employed to investigate the influence factors controlling paraffin wax deposition to the pipe wall surface (namely, inlet oil temperature, inlet coolant temperature, oil flow rate and the wax content). Series of tests were designed to determine the effects of these influence factors on the wax content in the deposit. The experimental results revealed that the amount of wax deposited initially increases with time, attained a maximum value and gradually erode off. Also it was discovered that the wax deposition decreases with flow rates and also with the temperature difference between the flowing oil and the pipe wall, when the oil temperature is above its Wax Appearance Temperature (WAT), while the reverse is the case when the oil temperature is below its WAT. The study also established that shear dispersion, defined as the movement of wax crystals towards the pipe wall as a result of the velocity variation along the radial direction during oil flow in the pipe ignored in most of the existing models used in the existing wax deposition commercial codes was found not to be inconsequential. The flow rate rather than the flow regime was also discovered to responsible for the shear stripping of wax deposit at the wall. This experimental observation will provide a reference point and an insight for further study on wax deposition in actual pipelines. This is particularly so for oil characterized by high wax content and high gel point temperature like those produced from most fields in Nigeria’s Niger Delta.
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    Open Access
    Hydrodynamics of Sand-Oil-Gas Multiphase Flow in a Deviated Petroleum Well
    (Nova Science Publishers, Inc., 2012-05) Adeyanju, O.
    A calculation method for predicting pressure profiles along the wellbore based on easily obtainable wellhead parameter has been the preferred method. But, the predictive capability of the existing correlations is a thing of concern. This is due to the inability of the existing models and correlations to account for the presence of the sand particles in the flow stream; also the requirement for the well to be shut-in in order to acquire the needed parameters is counter productive. These inadequacies were corrected in the proposed model. Results showed that the average pressure drop in the multiphase fluid flow using the proposed model is higher than the pressure drops determined using existing models and correlations. The effects of the fluid density, viscosity and velocity on the sand particles lifting were also investigated and results showed that the sand particles suspension and lifting were improved by higher fluid velocity and density and lower fluid viscosity (i.e. higher Reynolds number). Validation of the proposed model with field data showed that the model predicts the field BHP data better than any of the existing models and correlations, based on the Average Absolute Deviation (AAD) value of 6.53 returned by the proposed model compared to AAD value of between 13.56 and 24.67 returned by the existing models and correlations.
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    Open Access
    Modeling and Simulation of Scale Deposition during Water-flooding in Porous Media
    (Nova Science Publishers, Inc., 2012-11) Adeyanju, O.
    Mineral scale deposition within the reservoir due to incompatibility of the injected and the formation water can cause a significant decrease in reservoir performance. Few documentations of the damage cause by scale deposition to reservoir flow performance are available in the literature. In this paper a fully implicit numerical model was developed to model the deposition and concentration profiles of scales formed in the formation. The simulated results conform well when compared to the developed analytical solution to mimic the mineral scale deposition and concentration profiles. The model ability to shows the effects of changing porosities not acknowledged by the analytical model confirmed the effectiveness of the developed model. The results showed that the effect of permeability and porosity reductions is prominent in the near well-bore regions of the injection well. Also the higher the concentrations of the mineral scale in the mixture of the injected and formation water the higher the degree of formation damage. Hence efforts should be made to test the compatibility of the injected and formation water before embarking on a water-flooding project to prevent excessive damage to the reservoir. This will minimizes productivity reduction during the flooding.
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    Open Access
    Modeling of Gas-Liquid Stratified Flow in an Inclined Well-Bore and Bends
    (Nova Science Publishers, Inc., 2010-10) Adeyanju, O.; Oyekunle, L.
    Multiphase flows modeling in wellbore has always been a problem to the petroleum industry operators. Correlations are presently in use in the petroleum industry, and most of these correlations are obsolete as their application to field data has generated results with unacceptable errors. Most of the existing models proposed to correct these anomalies have always ignored the mass transfer between phases. This has creates serious doubt to the predictive capability of these models. In this study, a one-Dimensional transient state mechanistic model of multi-phase fluid flow in inclined well has been developed. The model is solved numerically to predict the pressure drop as the flow passes through an inclined wellbore and a bend. Results show that the higher the inclination angle the higher the rate of pressure decline in the flow of the fluid to the surface, also a dramatically high pressure drop was observed when the flow passes through a bend. This unexpected high pressure resulting from the change in flow regime from stratified layered flow to slug flow in bend can result in a counter flow of formation fluid back into the reservoir in a low pressure reservoir thereby reducing the fractional recovery from such reservoir. The models predicted the experimental pressure gradient results better than the existing correlations presently in used in the petroleum industry judging from the Average Absolute Deviation (AAD) value of 0.7 compared to AAD value of 1.9 and 2.4 returned by the correlations.
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    Open Access
    New Multi-Solid Thermodynamic Model for Improved Cloud Point Prediction of Waxy Crudes
    (Petroleum & Coal Publisher, 2010-07) Adeyanju, O.; Oyekunle, L.
    A thermodynamic framework is developed for calculating the cloud point also known as WAT (Wax Appearance Temperature) or WDT (Wax Disappearance Temperature) in petroleum mixtures. The method involves the use of experimental data to generate a correction’s correlation for the liquid molar volume shift parameter during liquid-solid equilibrium. Application of the method to the five ternary systems with the 72 equilibrium data points gives an AAD (Absolute Average Deviation) between 0.843 – 0.979. Also, the method gives a better performance in re-producing the experimental cloud point for real petroleum fluids. Its use is simple, accurate and has wide range of validity.
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    Open Access
    Optimization of Chemical Demulsifications of Water in Crude Oil Emulsions
    (Elsevier, 2019-10) Adeyanju, O.; Oyekunle, L.
    The instability of the water in crude oil emulsion and separation of the dispersed water as free water are influenced by the emulsion properties and the operating parameters during the demulsification process. This study aims to relate these properties/operating parameters to the amount of separated water. Steps were taken to determine and validate the optimal separations that can be achieved. Six operating parameters were identified through sensitivity analyses to have an energetic effect on percentage water separation. The bottle test method was used on two different samples of water in oil synthetic emulsions (sample A and B from different Nigerian oil fields). Response surface methodology central composite design (RSMCCD) was used to design the experiment, and generate the desired regression equations/ models. Results show that optimum percentage water separations of 93 and 95% (V/V) were achieved with the emulsions A and B respectively using the combination of the optimal variables derived from the model equations. These were improvements from percentage water separations of 80 and 83% (V/V) achieved using the two crude oil samples in their naturally occurring state when the properties of the emulsions were not enhanced to their determined optimal operating conditions.
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    Open Access
    Optimization of Natural Gas Transport in Pipeline
    (Centre for Advanced Training and Research, 2013-10) Adeyanju, O.; Oyekunle, L.
    Transportation of natural gas is a very important aspect of the oil and gas industry and as such, it must be done with a much efficiency. Pipelines has been recognized as the most economic, effective and safest way of transporting natural gas. A lot of capital is needed, due to cost of pipeline, compressor stations and also in its maintenance. Therefore in order to minimizing cost, optimization of natural gas transportation processes is necessary. In this study, optimization procedure of natural gas transportation network was developed using a workable procedure adapting the Generalized Reduced Gradient algorithm. It determines the optimum economical conditions natural gas can be transported through series of pipeline and compressors station. The model developed when applied to the Excravos Lagos pipeline network showed that total cost of flowing natural gas depends on the amount of gas to be transported and also on the outlet pressure required. Results show that depending on the require flow rate, some installed compressors need to be inactive for effective cost reduction. The required diameters to meet the corresponding demand (Flow rates) are presented for the future upgrade of the facilities. Also comparison of different gas flow equations showed that the optimum network configuration for panhandle A and B are almost the same, but for Weymouth equation, it widely varies. The developed model can be extended to treat much larger and more complex network.