Papers by BRIGHT B A R I A K P O A KINATE
Current Trends in Engineering Science (CTES), 2023
This work analyzed the amount of capillary-trapped CO 2 for maximum residual gas saturation due t... more This work analyzed the amount of capillary-trapped CO 2 for maximum residual gas saturation due to relative permeability hysteresis. Upward migration of CO 2 is unwanted because it increases the risk of CO 2 migration from storage sites to the surface. One way to mitigate CO 2 leakage risk is to reduce the vertical CO 2 migration to improved storage capacity and containment security. A compositional simulator (CMG-GEM) was used to simulate the flow of two components (CO 2 and H 2 O). A fluid model was built with the PR 78 EOS using WINPROP. A base case model without relative permeability hysteresis was simulated and compared with the case with relative permeability hysteresis. The amount of CO 2 trapped, and CO 2 saturation distribution were analyzed for maximum trapped gas saturation of 0.3, 0.4 and 0.5. Results shows an increase in the amount of CO 2 trapped as the maximum residual gas saturation was increased from 0.3 to 0.4 and 0.5 with a value of 16560128mol for the base case study, 49041744mol, 59502924mol and 67286728mol respectively for maximum residual gas saturation due to relative permeability hysteresis of 0.3, 0.4 and 0.5 respectively. Very little accumulation of CO 2 occurs when the maximum trapped gas saturation due to relative permeability hysteresis was set at 0.5. Result reveals that after 200 years, almost all the CO 2 was trapped in the formation. Therefore, the imbibition cycle at the trailing end of the CO 2 plume should be considered as accounting for hysteresis effects has led to a spread-out distribution of trapped CO 2 , as opposed to a concentrated distribution of mobile CO 2 without relative permeability hysteresis.
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American Journal of Applied Sciences and Engineering , 2023
This study evaluates the use of self-gas lifting in the mitigation of severe slugs. OLGA was used... more This study evaluates the use of self-gas lifting in the mitigation of severe slugs. OLGA was used to develop the pipeline model and Multiflash for fluid characterization. Two OLGA cases were created, a base case pipeline model which was inclined at 5° to the riser base and also a 5° inclined pipeline to the riser base but with an auxiliary bypass line to lift the flow at a certain point above the riser base. A phase splitter process equipment which acts as a takeoff point along the pipeline and function as an internal node and a separator network was place along the pipeline and riser. The phase splitter allows only gas to pass through the 'bypass line' and liquid through the 'Subsea Tieback'. The bypass pipe of internal diameter 3-inch was connected to the takeoff point at 535.455ft from the riser base along the pipeline and to an internal node which serves as the injection point into the riser at 20ft from the riser base. Results shows that an auxiliary self-lift bypass line was very effective in attenuating severe slugging in a pipeline-riser system and a stable liquid production of 2728.93bbl/day at the topsides was obtained when an auxiliary bypass line was used as a gas re-injection line into the riser column whereas for the case of 5° inclined pipeline without a bypass line, the total liquid flow was oscillating between 46776.3bbl/day and-3646.44bbl/day. Slug flow was completely eliminated for the model with bypass line as evidenced by the more stable pressure. The highest riser pressure was 291.327psia over the duration of the 2hrs, which was lower than the slugging model without a bypass line (299.595psia). The auxiliary self-lift bypass line was very effective in mitigating slugging in the pipeline-system.
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European Journal of Advances in Engineering and Technology, 2023
This work investigates the contribution of each reservoir in a commingled production through natu... more This work investigates the contribution of each reservoir in a commingled production through natural variation in geochemical fingerprinting of each reservoir fluid. Two oil samples and one gas sample were taken from three different locations in Niger Delta field; Well X of field A, Well Y of field B and Well Z of field C. Each well is producing from two commingled reservoirs through a single string as follows Res X1and X2 for Well X, Res Y1 and Y2 for Well Y and Res Z1 and Z2 for Well Z respectively. The samples were analyzed with Agilent Gas Chromatographic instrument equipped with Flame Ionization Detector (GC-FID) and HP-PONA capillary column. ASTM D2887 and GPA 2286 standard were used for oil and gas samples respectively. Artificial mixes were prepared using the end-members at different proportions and they were analyzed and quantified to generate allocation ratios. Production allocation plots were used to determine the percentage contribution of each reservoir in the commingled crude. The results showed that in field A, the contribution of Res X1 and Res X2 was 10% and 90%, respectively. In field B, Res Y1 contributed 60% and that of Res Y2 was 40% while in field C, Res Z1 and Z2 contribution was 30% and 70% respectively. The study showed that geochemical fingerprinting analysis using GC-FID is a proven alternative method for reservoir fluid production contribution in a commingled system. The method is time and cost efficient when compared with production logging approach.
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Journal of Earth Energy Science, Engineering, and Technology, 2022
This work investigates the impact of elevation on terrain-induced slugging in a riser system. Flu... more This work investigates the impact of elevation on terrain-induced slugging in a riser system. Fluid compositions were modeled with multiflash and exported to OLGA in a readable PVT Table File. Pipeline materials and properties with geometry of different elevation were modeled in OLGA to develop a flowline model. Two geometries (1 and 2) of different elevations were defined to establish their effect on accumulated liquid volume flow, surge liquid volume, slug length, number of slugs and slug density. The result shows that Geometry 1 with a total elevation(height)of 450 ft has a total liquid volume flow of 10.1058 ft 3 /s and Geometry 2 with a total elevation(height) of 300 ft has a total liquid volume flow of 0.197822 ft 3 /s for the same time of 2473.99 seconds. Also, Geometry 1 has a surge liquid volume of 543.4608484 ft 3 at a drain rate of 0.20843960 ft 3 /s and Geometry 2 with a surge liquid volume of 210.7395 ft 3 at a drain rate of 0.23892 ft 3 /s. There was no slug length and number of slugs in pipe of Geometry 1 while Geometry 2 has a slug length of 531.78 ft indicating severe slug in Geometry 2 system of different elevation. The slug density of Geometry 2 system was twice that of Geometry 1. Change in the elevation for the geometries has shown a significant effect on terrain-induced slugging in the pipe-riser system.
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Journal of Earth Sciences and Technology, 2022
Gas hydrate formation is a major flow assurance problem experience during production and transpor... more Gas hydrate formation is a major flow assurance problem experience during production and transportation of gas/condensate and is almost impossible to eliminate but can be prevented. Hydrate formation can occur and affected by the changes in composition, pressure and temperature of the hydrocarbon fluid. It is vital to prevent the formation of hydrate because of the harm it causes to production facilities. This study evaluates the insulation thickness requirements during a shut-down situation for gas hydrates formation Prevention. Gas properties and PVT table files were created and modelled in multiflash and exported in a readable format to OLGA. A pipeline model was built and developed in OLGA with pipeline materials and geometry data inputted. Polyethylene foam insulation materials was selected with varying thickness of 5mm, 10mm, 15mm, 20mm and 25mm after shutting down for twelve(12) hours to evaluate the effect on hydrate formation during shut down situation. Results indicate that increase in insulation thickness increases the point of hydrate stability along the pipeline. Also, increase in the insulation thickness decreases the hydrate volume fraction and no hydrate was form for 25mm insulation thickness. Hydrate formation in the pipeline can be avoided with the use of a high insulation thickness.
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Journal of Earth Energy Engineering, 2022
Hydrocarbon can be naturally produced from underneath fractured sandstone when pressure can no lo... more Hydrocarbon can be naturally produced from underneath fractured sandstone when pressure can no longer force fluids to the surface facilities. A satisfactory recovery factor for this production was conducted through the cost-effective enhanced oil recovery (EOR) method. Water alternated gas (WAG) injection is a promising EOR technique that combines the advantages of waterflooding and gas injection to achieve better mobility control, improved sweep efficiency, and overall recovery from the given reservoir. Therefore, this study aims to investigate the relationship of a miscible WAG to a core flood model using numerical simulation techniques (Eclipse Reservoir Simulator – Black Oil Model Option). In this case, reservoir X consisting of three wells drilled 15 years after the initial forecast showed that production cannot be sustained by natural depletion. Furthermore, the optimal WAG ratio was selected with different simulation scenarios using oil recovery factors to perform 12 simulation runs and study the influence of the WAG cycle period. The most effective WAG cycle scenario was 90W-30G with an oil recovery factor of 0.54684 (54.68 %) and cumulative production of 14.987MMSTB. The 30W-90G produced the lowest oil recovery factor and cumulative production of 0.47468 (47.47%) and 12.996MMSTB, respectively. Therefore, a higher water cycling period is required for better oil recovery. The recovery is also enhanced by lowering the rate of water to gas injection. The results showed that despite the predicted higher recovery factor, a lower WAG ratio indicated a potential of relatively low-pressure maintenance which can affect future recovery from the reservoir.
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International Journal of Petroleum and Petrochemical Engineering, 2021
This study examines the influence of permeability variations on the performance of polymer floodi... more This study examines the influence of permeability variations on the performance of polymer flooding in an enhanced oil recovery with the use of ECLIPSE simulator. A synthetic reservoir model (10x10x1) was constructed for two reservoir models, a heterogeneous system (Reservoir X-A) and a homogeneous system (Reservoir X-B).Both cases were simulated at same reservoir conditions by polymer injection at a rate and concentration of 200STB/day and 50Lb/STB and analyzed at a time stepping of 10days over a 10years field life.
The parameters analyzed were water relative permeability, oil relative permeability, oil-water capillary pressure, equivalent mixture viscosity, permeability reduction coefficient, block polymer adsorption, field pressure, field oil production rate and well flowing bottom hole pressure. Results revealed a fast reduction in the oil phase mobility for the heterogeneous system for high permeability above 25md and a water breakthrough for the producer in the homogeneous reservoir. Polymer adsorption rates in higher permeable zones are lower than the low permeable zone. The heterogeneous reservoir has the highest pressure decline while the homogeneous system has a better
production rates. The influence of permeable channels is more pronounced in the injection well vicinity.
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International Journal of Petroleum and Geoscience Engineering, 2021
This work presents a numerical simulation approach in evaluating concentration and adsorption of ... more This work presents a numerical simulation approach in evaluating concentration and adsorption of polymer during a polymer flooding using a 3-D composite reservoir model with 100 cells (10x10x1). The reservoir was produced with two wells-injection (INJ) and producer (PROD) which are positioned at (3, 3, 1) and (8,8,1) grids respectively. The parameters investigated are the polymer adsorption coefficients, polymer in solution, oil/water saturation, oil-water capillary pressure and field production outputs. An increase in the amount of polymer (in solution) and the resulting polymer concentration and adsorption was fast in the producer grid cell (3, 3, 1) and slow in the grids at the extreme ends-(1, 1, 1) and (10, 10, 1). The presence of high permeability streaks along the central axis of the diagonal grid cells influences the polymer concentration distribution and adsorption. Hence, despite the equal spatial differences of grid cells (1,1,1) and (5, 5, 1) from the injector grid at (3, 3, 1), the amount of polymer in solution and the actual polymer concentration were far apart and not comparable. In the absence of reservoir fractures (or heterogeneity), advancement of polymer in water phase is relatively subject to the location of the injection well and the producer well.
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Original article, 2020
Gas condensate fields are quite lucrative fields because of the highly economic value of condensa... more Gas condensate fields are quite lucrative fields because of the highly economic value of condensates. However, the development of these fields is often difficult due to retrograde condensation resulting to condensate banking in the immediate vicinity of the wellbore. In many cases, adequate characterization and prediction of condensate banks are often difficult leading to poor technical decisions in the management of such fields. This study will present a simulation performed with Eclipse300 compositional simulator on a gas condensate reservoir with three case study wells-a gas injector (INJ1) and two producers (PROD1 and PROD2) to predict condensate banking. Rock and fluid properties at laboratory condition were simulated to reservoir conditions and a comparative method of analysis was used to efficiently diagnose the presence of condensate banks in the affected grid-blocks. Relative Permeability to Condensate and gas and saturation curves shows condensate banks region. The result ...
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European Journal of Engineering Research and Science
The extent of damage to formation caused by water based drilling mud containing corn cob treated ... more The extent of damage to formation caused by water based drilling mud containing corn cob treated with sodium hydroxide to partially replace polyanionic cellulose (PAC) as a fluid loss control additive has been studied. Core samples were obtained from a well in Niger Delta for this study with a permeameter used to force the drilling mud into core samples at high pressures. Physio-chemical properties (moisture content, cellulose and lignin) of the samples were measured and the result after treatment showed reduction. The corn cob was combined with the PAC in the ratio of 25-75%, 50-50% and 75-25% in the mud. Analyzed drilling mud rheological properties such as plastic viscosity, apparent viscosity, yield point and gel strength all decreased as percentage of corn cob increased in the combination and steadily decreased as temperature increased to 200oF. Measured fluid loss and pH of the mud showed an increase in fluid loss and pH in mud sample with 100% corn cob. The extent of formation...
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International Journal of Engineering and Modern Technology, 2021
The effect of temperature (100 o C to 280 o C) on the petrophysical properties (permeability and ... more The effect of temperature (100 o C to 280 o C) on the petrophysical properties (permeability and porosity) and recovery potential of designed oilsand reservoir was investigated. Core samples were obtained from Edo state in Nigeria and steam at different temperatures was injected into the oilsand reservoir. The core experiment indicates that the porosity and permeability of a tight formation such as that of oilsand at ambient temperature is 0.038 and 0.007 MD respectively. A rise in the temperature of the formation due to the injection of steam caused an alteration in the petrophysical properties (porosity and permeability) of the reservoir. Samples analysed after the injection of steam at different temperatures showed a decrease in porosity and an increase in the permeability of the formation. Increase in the porosity and permeability of the formation increases the recovery of heavy oil from the reservoir.
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International Journal of Scientific Research in Multidisciplinary Studies, 2021
The discovery of non-flowing oil wells poses a significant challenge to the Oil and Gas industry'... more The discovery of non-flowing oil wells poses a significant challenge to the Oil and Gas industry's quest for a cost-effective, profitable, and safe business of maximizing production from producing wells. Production from such wells requires the application of an artificial lift system to supplement or maintain reservoir pressure, which is generally seen as the major factor for a non-flowing well condition. It is, however, necessary to troubleshoot a non-flowing well by conducting diagnostic analyses on both the reservoir and well parameters, in order to determine the actual parameter(s) accountable to the state of a non-flowing well condition. This work considers water-cut, reservoir pressure, and reservoir temperature as the major parameters in conducting integrated diagnostic analyses on a non-flowing well. Two case scenarios were studied on the well-conducting diagnostic analyses on the non-flowing well, and application of a Hydraulic Driven Downhole Pump on the same well. Results of the first case scenario shows that reservoir pressure was the dominant factor for a non-flowing condition in the well as a reservoir pressure of 3611.11psig enabled the well to flow even at an operating envelope of a water-cut value of 73.333% and a near reservoir temperature of 266.667°F, with respect to the given reservoir temperature of 250°F. At such operating envelope, the well produced at an oil rate of 1039.2 STB/day, gas rate of 0.41567 MMscf/day, water rate of 2857.8 STB/day, and a liquid rate of 3896.9 STB/day. In the second case scenario, the well flows even at a low reservoir pressure of 888.889 psig, producing at an oil rate of 962.8 STB/day, a gas rate of 0.38511 MMscf/day, a water rate of 3851.1 STB/day, and a liquid rate of 4813.9 STB/day. At reservoir pressures higher than 888.889 psig, the well yields higher oil production rates.
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World Academics Journal of Engineering Sciences, 2020
The invasion of mud filtrates in to the permeable formation is an inevitable experience during dr... more The invasion of mud filtrates in to the permeable formation is an inevitable experience during drilling operations. It is usually associated with near-complete formation damage in the immediate vicinity of wellbore and the response of well log tools (especially the low penetration tools) are then greatly influenced by the mud filtrates instead of formation fluids which makes its interpretation more difficult. Hence, it is often necessary to know the possible spatial and time variation of mud filtrate concentrations in the porous media during invasion. This study presents a model technique for the numerical simulation of rate of mud invasion using a pressure transient analogy of mud concentration gradient. The model uses a finite difference element of 1000ft 3 divided into five (5) uniform gridblocks of length, 2ft each. The results of the study showed clearly that from the time and space of invasion process initialisation, the mud concentration diffuses into the porous medium. At early time of invasion, the mud filtrate is continuously diffused into the porous media while at later stage of invasion, mud concentration builds from the inner gridblocks facilitating the formation of filter cake at the wellbore. Further analysis of the results reveals that the displacement of the in-situ formation fluid by the invading mud is not a piston-like phenomenon as shown by the spatial variation of the mud filtrates concentration during the invasion period. However, the concentration gradient can be used to define the extent of mud filtrate invasion into the permeable formation
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European Journal of Engineering Research, 2020
The extent of damage to formation caused by water based drilling mud containing corn cob treated ... more The extent of damage to formation caused by water based drilling mud containing corn cob treated with sodium hydroxide to partially replace polyanionic cellulose (PAC) as a fluid loss control additive has been studied. Core samples were obtained from a well in Niger Delta for this study with a permeameter used to force the drilling mud into core samples at high pressures. Physio-chemical properties (moisture content, cellulose and lignin) of the samples were measured and the result after treatment showed reduction. The corn cob was combined with the PAC in the ratio of 25-75%, 50-50% and 75-25% in the mud. Analyzed drilling mud rheological properties such as plastic viscosity, apparent viscosity, yield point and gel strength all decreased as percentage of corn cob increased in the combination and steadily decreased as temperature increased to 200 o F. Measured fluid loss and pH of the mud showed an increase in fluid loss and pH in mud sample with 100% corn cob. The extent of formation damage was determined by the differences in the initial and final permeability of the core samples. Experimental data were used to develop analytical models that can serve as effective tool to predict fluid loss, rheological properties of the drilling mud at temperature up to 200 o F and percentage formation damage at 100 psi. Index Terms-corn cob, fluid loss,formation damage, water based mud.
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International Journal of Advancement in Research &Technology, 2020
This study investigates the diagnosis and control of excessive water production in oil wells in t... more This study investigates the diagnosis and control of excessive water production in oil wells in the Niger Delta oilfields. The diagnostic plots derivatives approach was adopted. Production data were obtained from two wells and Prosper was used for the analysis. Chan's model was used for diagnosis and Water Shut-off techniques were used in control of excessive water in the case study fields. The results indicate that there is increase in production when the intervals with excessive water was shut-off and shallower intervals were perforated and monitoring of wells near terminal water-cut. The results revealed that some of the causes of excessive water production in the oil fields are channel casting leaks, open fracturing out of zones, completion in to or near water, barrier breakdown, channeling through higher permeability zones or fractures, and coning and cresting and no proper well surveillance and wells reservoir and facility management in place. For the first well NDZ_A, the initial water-cut of 60% was reduced to 0.3% with a production increase of 412 Bopd and for the second well NKZ_B of initial water-cut of 43% was reduced to 0% with a production increase of 968 Bopd. This study concludes that in hydrocarbon production, often oil produced commingled with water. As long as the water production rate is below the economic level of water/oil ratio (WOR), no water shut-off treatment is needed. Problems arise when water production rate exceeds the WOR economic level, producing no or little oil with it. Therefore, it is necessary that effective evaluation of the intervention procedure is carried out and expected outcome using the production performance data should be encouraged.
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International Journal of Scientific Research in Multidisciplinary Studies, 2020
Horizontal wells are drilled essentially with the aim of recovering more oil or gas than a vertic... more Horizontal wells are drilled essentially with the aim of recovering more oil or gas than a vertical well. The ratio of horizontal and vertical well productivity is one of the basic considerations in the decision to drill either a horizontal or vertical well. Attempts have been made to describe and estimate horizontal well productivity and injectivity indices, sweep efficiency, and several models have been proposed for this purpose. In this work, Matrix Laboratory (MATLAB) was used to model horizontal well indices with three analytical methods. Model results were compared with each other and with results from simulation using PETEX PROSPER single well modeling tool. Result obtained shows that increase in well length, pay thickness and anisotropy increases the productivity for all the models. Borisov's model has the highest productivity index at different well depth and pay thickness. Joshi's model result for the productivity index was the closest to the PETEX PROSPER result with a percentage error of approximately 3%, followed by Elgagah et al, and Borisov respectively. Discrepancies in model results are due to the varying assumptions inherent in the development of these models. Also, the effects of various well and reservoir properties such as well length, well thickness, permeability ratio and drainage area on horizontal well productivity was analyzed. The optimal well productivity for horizontal well will be realized from a thin reservoir with high vertical permeability and sufficient well length without compromising the ability for efficient drilling, completion and perforation, and a compact well spacing design.
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IOSR Journal of Engineering, 2020
A Borehole instability problem contributes significantly to increase in non-productive time (NPT)... more A Borehole instability problem contributes significantly to increase in non-productive time (NPT) and overall cost of the drilling. These problems can occur in a variety of forms including stuck pipe, loss circulation, hole enlargement, breakout. Borehole problems such as drill pipe sticking, hole collapse, breakout, ,caving and tight holes have been experienced during drilling of wells in an oil field in the Niger Delta. This work analyzed the major cause of wellbore instability in a field in the Niger Delta by using data from two wells drilled and proposes an optimum mud window for cost-effective and safe drilling operations. Geomechanical model was used to evaluate the in-situ stress and induced stresses with Mogi Coulomb and Mohr Coulomb failure criteria to predict the breakout profile and estimate the optimum mud weight to avoid sticking of the drill string. The result shows that the Mogi failure criterion was 1.46sg and 1.39sg while Mohr failure criteria were 1.48sg and 1.42sg for well 1 and well 2 respectively. Based on the results obtained, Mogi coloumb is preferable to Mohr coloumb criteria. Mogi failure criteria give more accurate result to obtain optimum mud weight window for the field considered in the Niger Delta. Therefore, in the prediction of an optimum mud weight window for any well in the Niger Delta, mohr failure criteria should be employed and adopted.
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International Journal of Recent Engineering Science, 2020
The Oil and Gas Industry are faced with problems caused by the formation of water-in-crude oil em... more The Oil and Gas Industry are faced with problems caused by the formation of water-in-crude oil emulsions and crude oil in water emulsion resulting to loss of huge sum of money to treat and for market specification. The existence of water along with the crude oil that is being produced is undesirable because of problems directly correlated to foaming, corrosion of pipelines and tanks, higher power consumption, and increased volume and viscosity. Several methods have been employed to solve these problem, but still open due to inefficiency and divergence of views. The choice of surfactant and what concentration, have been a challenge for proper dissolution of the emulsion. Hence, this project work covers
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International Journal of Engineering Applied Sciences and Technology, 2020
Crude oil emulsions pose significant problems to petroleum production and processing and as such ... more Crude oil emulsions pose significant problems to petroleum production and processing and as such have received serious attention towards providing lasting solutions to alleviate these production problems. The use of surfactants and demulsifiers has proven to be industry's most recognized method for the treatment of crude oil emulsions. In this study a laboratory investigation was carried out in order to determine the effect of surfactant, Sodium Lauryl Sulphate (SLS) and demulsifier (Hexane) on emulsion treatment at different concentrations. Two samples of crudes (IMOR3-023L and AGBDI-013L) were used with Sodium Lauryl Sulphate (SLS) as surfactant, Hexane as the demulsifier and Toluene as a stabilizer to form an emulsion. For each crude sample, eight (8) samples of emulsions were formulated with varying volume concentrations of the water, demulsifier and surfactant. For all the samples, Toluene (stabilizer) was kept constant while the demulsifier (Hexane) is kept constant and surfactant (SLS) varied for the first test. For the second test, the Hexane (demulsifer) was varied and SLS(Surfactant) was constant. The result shows that when Toluene and Hexane were kept constant with SLS varied, sample A has significant increase in the volume of water separated from 13ml to 16ml for range of 1hr to 5hrs and Sample B with volume of water separated from 3.8ml to 10.1ml for range of 1hr to 5hrs. Similarly, sample C and D recorded significant increase also when Toluene and SLS was kept constant with Hexane varied. Sample I and sample J has significant increase in the volume of water separated from 3ml to 9.9ml and 12ml to 12.9ml for range of 1hr to 5hrs. In general, varying the volume of Hexane has higher percentage of water recovered and separated than SLS. This research has shown the effectiveness of chemical method for crude oil emulsion treatment and should be adopted as separation will be fast and less expensive.
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African Journal of Engineering and Environment Research, 2020
As drilling optimization becomes the major concern of the drilling engineer and the mud specialis... more As drilling optimization becomes the major concern of the drilling engineer and the mud specialist, there is therefore need to properly evaluate key success factors that ultimately affects the success of drilling operations. This research work examined the effects of fluid rheology and cuttings size on cuttings transportation in vertical wells. To achieve that, an experiment was conducted on two samples of fresh oil-based mud (A and B) of different rheology and two drilled cuttings sample (A and B) of sizes 400µm and 1000µm obtained from Anieze North field after sieve analysis. The drilled cuttings samples(A and B) were comingled with the mud(A and B) and their rheology (viscosity, density, plastic viscosity, yield point and gel strength) and cuttings transport parameters (slip velocity, transport velocity, transport ratio and transport efficiency) were checked at different temperatures. The cuttings transport parameters generated with the test models (Moore, Chien et al, and Zeidler) reveal that drilled cuttings of smaller size are easily transported than those of larger size. It was also observed that temperature has remarkable effects on rheology and slip velocity. Hence, slip velocity increases with temperature, while rheological values decrease with temperature. As a recommendation arising from the results of this investigation, a lower cuttings size should be ensured in a low viscous fluid for an efficient hole-cleaning. Apart from the aforementioned factors for efficient transportation of drilled cuttings, drilling bit configuration which is major determinant of the size of cuttings should be properly examined before selection for any drilling operation.
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Papers by BRIGHT B A R I A K P O A KINATE
The parameters analyzed were water relative permeability, oil relative permeability, oil-water capillary pressure, equivalent mixture viscosity, permeability reduction coefficient, block polymer adsorption, field pressure, field oil production rate and well flowing bottom hole pressure. Results revealed a fast reduction in the oil phase mobility for the heterogeneous system for high permeability above 25md and a water breakthrough for the producer in the homogeneous reservoir. Polymer adsorption rates in higher permeable zones are lower than the low permeable zone. The heterogeneous reservoir has the highest pressure decline while the homogeneous system has a better
production rates. The influence of permeable channels is more pronounced in the injection well vicinity.
The parameters analyzed were water relative permeability, oil relative permeability, oil-water capillary pressure, equivalent mixture viscosity, permeability reduction coefficient, block polymer adsorption, field pressure, field oil production rate and well flowing bottom hole pressure. Results revealed a fast reduction in the oil phase mobility for the heterogeneous system for high permeability above 25md and a water breakthrough for the producer in the homogeneous reservoir. Polymer adsorption rates in higher permeable zones are lower than the low permeable zone. The heterogeneous reservoir has the highest pressure decline while the homogeneous system has a better
production rates. The influence of permeable channels is more pronounced in the injection well vicinity.