Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. I...Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. Individual well’s ESP frequencies have to be constantly updated to ensure optimum oil productions from the field. The choice of the ESP frequency to be used must come from sound engineering decisions which do not come from mere intuition but must be backed up by mathematical models and computer simulations. This study proposes to evaluate field production network optimization on ESP lifted wells using quadratic sequential programming techniques. The optimization approach seeks to determine the ESP frequency for each well that will lead to the maximum field oil production while honouring the field operational constraints. Two reservoirs and five wells were considered. The non-linear optimization problem for the ESP lifted wells in the field was formulated with their boundary conditions. The simulations were performed in Prosper and GAP software. Prosper software was used in building the individual well’s ESP models for the five wells in the field. Individual well’s model in Prosper was exported to GAP and simulations were run in GAP for the field network system. GAP simulations were run in two cases: case 1 comprises ESP simulation without optimization while case 2 comprises ESP simulation with optimization. For case 1, fixed values of ESP frequency were selected for each well and the GAP software calculates the production rates from the wells in the network accruing from the ESP frequencies inputted. For case 2, there was no input ESP frequency as the GAP software was allowed to calculate based on optimization algorithms, the best suitable ESP frequencies for each well in the field that will lead to the maximum total oil production in the field network while honouring the operational constraint imposed on the systems in the field. From the results, it was realized that at the basis of well, the 展开更多
The market worth of the crude oil transported to the international market has a great influence on the crude’s physical properties, as such demands that certain desirable physical properties ought to be possessed. Th...The market worth of the crude oil transported to the international market has a great influence on the crude’s physical properties, as such demands that certain desirable physical properties ought to be possessed. The distillation of crude oil is the first process in the sequence of refining operation and is key to refinery operations profitability. In this work, five crude oil samples were collected from a reservoir in the Niger Delta designated as S11A, S12A, S13A, S14A and S15A. Sample S11A was not treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc while samples S12A-S15A were treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc at different number of times. This was necessary to ascertain the effect of the bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc on crude oil physical properties and their distillate yield. After the treatment, the specific gravity, American Petroleum Institute (API), pour point, flash point and viscosity of the treated and untreated crude samples were determined and then the samples distilled with a distillation tester. From the results obtained, the bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc had </span><span style="font-family:Verdana;">a </span><span style="font-family:Verdana;">great influence on the physical properties of the samples as well as on the distillate yield. The specific gravities of the oil samples decreased as the number of times the samples were treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc increases and this in turn increased the crudes’ API. The pourpoint and viscosity decreased with increase in number of treatments of crude samples with bio-disc. As the number of treatments increased, the crude samples which were originally paraffinic were tending towards being naphthenic. The flash point and distilla展开更多
Hydraulic fracturing is among the approaches used to optimize production from a gas condensate reservoir. A detailed economic analysis is required to evaluate the profitability and feasibility of hydraulic fracturing ...Hydraulic fracturing is among the approaches used to optimize production from a gas condensate reservoir. A detailed economic analysis is required to evaluate the profitability and feasibility of hydraulic fracturing as an optimization option in a gas condensate reservoir operating below dewpoint. The objective of this research is to evaluate the economic benefits derivable from the use of hydraulic fracturing to improve gas and liquid recovery from a gas condensate reservoir operating below dewpoint. This research considers the use of four profit indicators to ascertain the profitability of hydraulic fracturing in a gas condensate reservoir operating below dewpoint by increasing the fracture halflength, fracture width and fracture permeability. The production data of the reservoir was obtained and the economic calculations done on excel spreadsheet and plots generated. The four profit indicators considered in the research are Net Present Value, Payout, Discounted Cash Flow Rate of Return and Profit per Dollar Invested. The economic justification was done by carrying out a comparative economic analysis from the result obtained when the reservoir of study was unfractured with that obtained when the reservoir was fractured at various fracture parameters. The economic analysis was done considering a royalty and tax rate of 18.5% and 30% respectively and a gas price of $2/MSCF and condensate price of $30/bbl. This is done so as to find out if the additional cost of hydraulic fracturing can be offset by the recovery from the reservoir when its pressure declined below dewpoint. The result obtained showed that the additional recovery due to hydraulic fracturing by increasing the fracture halflength, fracture width and fracture permeability was not enough to justify the application of hydraulic fracturing when the reservoir pressure declined below dewpoint.展开更多
Shales have very low permeabilities often within the range of nanodarcies and as such production from shales have been complex and challenging because of poor conductive network. In this work, experiments were conduct...Shales have very low permeabilities often within the range of nanodarcies and as such production from shales have been complex and challenging because of poor conductive network. In this work, experiments were conducted to ascertain the effect of matrix acidizing on oil recovery of shale formation in the Niger Delta. Four core samples, S1, S2, S3 and S4 gotten from the Niger Delta shale formation were used. Experiments carried out focused on gas flooding using nitrogen gas at pressures of 1300 psia, 1800 psia and 2300 psia before acid treatment and acidizing with HCL as the choiced acid at different concentrations. XRD was used to analyze the mineral content of the core samples and the analyzed result shows that the predominant mineral constituents of the shale samples are calcite (47%) and dolomite (11%), which are HCl acid soluble constituents. At the end of the experiment, study revealed increase in oil production indicating enhanced productivity as a result of acid treatment and appropriate injection pressure of 800 psia. The result also revealed that the penetration rate in the range of 247.66 min/in to 139.95 min/in before acid treatment decreased to the range 21.67 min/in to 6.61 min/in after acid treatment.展开更多
There is a need to increase ultimate recovery from petroleum reservoirs. In order to guarantee efficient resource extraction from reservoirs, primary recovery methods cannot be relied on throughout the life of a well....There is a need to increase ultimate recovery from petroleum reservoirs. In order to guarantee efficient resource extraction from reservoirs, primary recovery methods cannot be relied on throughout the life of a well. There is a time in the life of a reservoir when the primary energy will not be sufficient to ensure economic recovery. Complete abandonment of the reservoir at this point may not be a sound engineering decision given the huge investments in developing the asset. Secondary recovery methods present potentials for the recovery of the other trapped resources. The choice of the secondary recovery means depends on the reservoir and geologic conditions and should be determined by modeling and simulation. In this work, a simulation study is conducted for Niger Delta Field ABX2 to determine the performance of water-flooding and gas injection in the recovery of the asset after the primary recovery stage. ECLIPSE Blackoil simulator was used for the modeling and simulation. An equal reservoir rectangular grid block was designed for both the waterflooding and water injection comprising a total of 750 grid cells. Water and gas were injected in both cases at an injection rate of 11,000 stb/d and 300,000 scf/d for waterflooding and gas injection respectively. From the results of the simulation, it was realized that waterflooding gave a higher total oil recovery than gas injection. The difference in oil recovery from water-flooding and gas injection amounted to 0.08 MMstb/d. The Field Oil Recovery Efficiency (FOE) for waterflooding and gas injection was 38% and 16% respectively giving a difference of 22%. The waterflooding method was troubled with excessive water cuts due to water breakthroughs. Waterflooding was chosen against gas injection to be applied to Field ABX2 to improve recovery after primary production ceased.展开更多
Accurate determination of hydraulic parameters such as pressure losses, equivalent circulation density (ECD), etc. plays profound roles in drilling, cementing and other well operations. Hydraulics characterization req...Accurate determination of hydraulic parameters such as pressure losses, equivalent circulation density (ECD), etc. plays profound roles in drilling, cementing and other well operations. Hydraulics characterization requires that all factors are considered as the neglect of any could become potential sources of errors that would be detrimental to the overall well operation. Drilling Hydraulics has been extensively treated in the literature. However, these works almost entirely rely on the assumption that the drill string lies perfectly at the center of the annulus—the so-called “concentric annulus”. In reality, concentricity is almost never achieved even when centralizers are used. This is because of high well inclination angles and different string geometries. Thus, eccentricity exists in practical oil and gas wells especially horizontal and extended reach wells (ERWs) and must be accounted for. The prevalence of drillstring (DS) eccentricity in the annulus calls for a re-evaluation of existing hydraulic models. This study evaluates the effect of drilling fluid rheology types and DS eccentricity on the entire drilling hydraulics. Three non-Newtonian fluid models were analyzed, viz: Herschel Bulkley, power law and Bingham plastic models. From the results, it was observed that while power law and Bingham plastic models gave the upper and lower hydraulic values, Herschel Bulkley fluid model gave annular pressure loss (APL) and ECD values that fall between the upper and lower values and provide a better fit to the hydraulic data than power law and Bingham plastic fluids. Furthermore, analysis of annular eccentricity reveals that APLs and ECD decrease with an increase in DS eccentricity. Pressure loss reduction of more than 50% was predicted for the fully eccentric case for Herschel Bulkley fluids. Thus, DS eccentricity must be fully considered during well planning and hydraulics designs.展开更多
The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding expe...The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding experiments and measurement of dispersion were performed on four core samples which were grouped into two: group A which were not fired and group B which were fired at a temperature of 500°C for 24 hours. Two low saline brines were prepared: LS1 which was derived by the dilution of seawater four times and LS2 which was derived by ten times diluting the seawater. The surfactant used was ethoxylated alcohol surfactant. Coreflood experiments were then performed on the rock samples starting with the injection of low saline followed by low saline brine combined with surfactant (LSS). Results from the experiments show that with the injection of LS1 brine and LSS1 higher increment in recoveries were obtained for group B than for group A cores. The same trend was also noticed with the injection of LS2 and LSS2. From the results, LS1 gave higher increment in oil recovery than LS2. Also LSS1 gave higher recoveries when compared with LSS2. In all the cases tested, core samples which were fired gave higher recoveries even though they had low permeabilities of 993 md for sample 3 and 1017 md for sample 4 than those which were not fired with higher permeabilities of 1050 md and 1055 md for samples 1 and 2 respectively. This was attributed to the alteration of wettability as well as that of permeability caused by sample firing. The dispersion profiles of the rock samples show that all samples are homogeneous.展开更多
文摘Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. Individual well’s ESP frequencies have to be constantly updated to ensure optimum oil productions from the field. The choice of the ESP frequency to be used must come from sound engineering decisions which do not come from mere intuition but must be backed up by mathematical models and computer simulations. This study proposes to evaluate field production network optimization on ESP lifted wells using quadratic sequential programming techniques. The optimization approach seeks to determine the ESP frequency for each well that will lead to the maximum field oil production while honouring the field operational constraints. Two reservoirs and five wells were considered. The non-linear optimization problem for the ESP lifted wells in the field was formulated with their boundary conditions. The simulations were performed in Prosper and GAP software. Prosper software was used in building the individual well’s ESP models for the five wells in the field. Individual well’s model in Prosper was exported to GAP and simulations were run in GAP for the field network system. GAP simulations were run in two cases: case 1 comprises ESP simulation without optimization while case 2 comprises ESP simulation with optimization. For case 1, fixed values of ESP frequency were selected for each well and the GAP software calculates the production rates from the wells in the network accruing from the ESP frequencies inputted. For case 2, there was no input ESP frequency as the GAP software was allowed to calculate based on optimization algorithms, the best suitable ESP frequencies for each well in the field that will lead to the maximum total oil production in the field network while honouring the operational constraint imposed on the systems in the field. From the results, it was realized that at the basis of well, the
文摘The market worth of the crude oil transported to the international market has a great influence on the crude’s physical properties, as such demands that certain desirable physical properties ought to be possessed. The distillation of crude oil is the first process in the sequence of refining operation and is key to refinery operations profitability. In this work, five crude oil samples were collected from a reservoir in the Niger Delta designated as S11A, S12A, S13A, S14A and S15A. Sample S11A was not treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc while samples S12A-S15A were treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc at different number of times. This was necessary to ascertain the effect of the bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc on crude oil physical properties and their distillate yield. After the treatment, the specific gravity, American Petroleum Institute (API), pour point, flash point and viscosity of the treated and untreated crude samples were determined and then the samples distilled with a distillation tester. From the results obtained, the bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc had </span><span style="font-family:Verdana;">a </span><span style="font-family:Verdana;">great influence on the physical properties of the samples as well as on the distillate yield. The specific gravities of the oil samples decreased as the number of times the samples were treated with bio</span><span style="font-family:Verdana;">-</span><span style="font-family:Verdana;">disc increases and this in turn increased the crudes’ API. The pourpoint and viscosity decreased with increase in number of treatments of crude samples with bio-disc. As the number of treatments increased, the crude samples which were originally paraffinic were tending towards being naphthenic. The flash point and distilla
文摘Hydraulic fracturing is among the approaches used to optimize production from a gas condensate reservoir. A detailed economic analysis is required to evaluate the profitability and feasibility of hydraulic fracturing as an optimization option in a gas condensate reservoir operating below dewpoint. The objective of this research is to evaluate the economic benefits derivable from the use of hydraulic fracturing to improve gas and liquid recovery from a gas condensate reservoir operating below dewpoint. This research considers the use of four profit indicators to ascertain the profitability of hydraulic fracturing in a gas condensate reservoir operating below dewpoint by increasing the fracture halflength, fracture width and fracture permeability. The production data of the reservoir was obtained and the economic calculations done on excel spreadsheet and plots generated. The four profit indicators considered in the research are Net Present Value, Payout, Discounted Cash Flow Rate of Return and Profit per Dollar Invested. The economic justification was done by carrying out a comparative economic analysis from the result obtained when the reservoir of study was unfractured with that obtained when the reservoir was fractured at various fracture parameters. The economic analysis was done considering a royalty and tax rate of 18.5% and 30% respectively and a gas price of $2/MSCF and condensate price of $30/bbl. This is done so as to find out if the additional cost of hydraulic fracturing can be offset by the recovery from the reservoir when its pressure declined below dewpoint. The result obtained showed that the additional recovery due to hydraulic fracturing by increasing the fracture halflength, fracture width and fracture permeability was not enough to justify the application of hydraulic fracturing when the reservoir pressure declined below dewpoint.
文摘Shales have very low permeabilities often within the range of nanodarcies and as such production from shales have been complex and challenging because of poor conductive network. In this work, experiments were conducted to ascertain the effect of matrix acidizing on oil recovery of shale formation in the Niger Delta. Four core samples, S1, S2, S3 and S4 gotten from the Niger Delta shale formation were used. Experiments carried out focused on gas flooding using nitrogen gas at pressures of 1300 psia, 1800 psia and 2300 psia before acid treatment and acidizing with HCL as the choiced acid at different concentrations. XRD was used to analyze the mineral content of the core samples and the analyzed result shows that the predominant mineral constituents of the shale samples are calcite (47%) and dolomite (11%), which are HCl acid soluble constituents. At the end of the experiment, study revealed increase in oil production indicating enhanced productivity as a result of acid treatment and appropriate injection pressure of 800 psia. The result also revealed that the penetration rate in the range of 247.66 min/in to 139.95 min/in before acid treatment decreased to the range 21.67 min/in to 6.61 min/in after acid treatment.
文摘There is a need to increase ultimate recovery from petroleum reservoirs. In order to guarantee efficient resource extraction from reservoirs, primary recovery methods cannot be relied on throughout the life of a well. There is a time in the life of a reservoir when the primary energy will not be sufficient to ensure economic recovery. Complete abandonment of the reservoir at this point may not be a sound engineering decision given the huge investments in developing the asset. Secondary recovery methods present potentials for the recovery of the other trapped resources. The choice of the secondary recovery means depends on the reservoir and geologic conditions and should be determined by modeling and simulation. In this work, a simulation study is conducted for Niger Delta Field ABX2 to determine the performance of water-flooding and gas injection in the recovery of the asset after the primary recovery stage. ECLIPSE Blackoil simulator was used for the modeling and simulation. An equal reservoir rectangular grid block was designed for both the waterflooding and water injection comprising a total of 750 grid cells. Water and gas were injected in both cases at an injection rate of 11,000 stb/d and 300,000 scf/d for waterflooding and gas injection respectively. From the results of the simulation, it was realized that waterflooding gave a higher total oil recovery than gas injection. The difference in oil recovery from water-flooding and gas injection amounted to 0.08 MMstb/d. The Field Oil Recovery Efficiency (FOE) for waterflooding and gas injection was 38% and 16% respectively giving a difference of 22%. The waterflooding method was troubled with excessive water cuts due to water breakthroughs. Waterflooding was chosen against gas injection to be applied to Field ABX2 to improve recovery after primary production ceased.
文摘Accurate determination of hydraulic parameters such as pressure losses, equivalent circulation density (ECD), etc. plays profound roles in drilling, cementing and other well operations. Hydraulics characterization requires that all factors are considered as the neglect of any could become potential sources of errors that would be detrimental to the overall well operation. Drilling Hydraulics has been extensively treated in the literature. However, these works almost entirely rely on the assumption that the drill string lies perfectly at the center of the annulus—the so-called “concentric annulus”. In reality, concentricity is almost never achieved even when centralizers are used. This is because of high well inclination angles and different string geometries. Thus, eccentricity exists in practical oil and gas wells especially horizontal and extended reach wells (ERWs) and must be accounted for. The prevalence of drillstring (DS) eccentricity in the annulus calls for a re-evaluation of existing hydraulic models. This study evaluates the effect of drilling fluid rheology types and DS eccentricity on the entire drilling hydraulics. Three non-Newtonian fluid models were analyzed, viz: Herschel Bulkley, power law and Bingham plastic models. From the results, it was observed that while power law and Bingham plastic models gave the upper and lower hydraulic values, Herschel Bulkley fluid model gave annular pressure loss (APL) and ECD values that fall between the upper and lower values and provide a better fit to the hydraulic data than power law and Bingham plastic fluids. Furthermore, analysis of annular eccentricity reveals that APLs and ECD decrease with an increase in DS eccentricity. Pressure loss reduction of more than 50% was predicted for the fully eccentric case for Herschel Bulkley fluids. Thus, DS eccentricity must be fully considered during well planning and hydraulics designs.
文摘The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding experiments and measurement of dispersion were performed on four core samples which were grouped into two: group A which were not fired and group B which were fired at a temperature of 500°C for 24 hours. Two low saline brines were prepared: LS1 which was derived by the dilution of seawater four times and LS2 which was derived by ten times diluting the seawater. The surfactant used was ethoxylated alcohol surfactant. Coreflood experiments were then performed on the rock samples starting with the injection of low saline followed by low saline brine combined with surfactant (LSS). Results from the experiments show that with the injection of LS1 brine and LSS1 higher increment in recoveries were obtained for group B than for group A cores. The same trend was also noticed with the injection of LS2 and LSS2. From the results, LS1 gave higher increment in oil recovery than LS2. Also LSS1 gave higher recoveries when compared with LSS2. In all the cases tested, core samples which were fired gave higher recoveries even though they had low permeabilities of 993 md for sample 3 and 1017 md for sample 4 than those which were not fired with higher permeabilities of 1050 md and 1055 md for samples 1 and 2 respectively. This was attributed to the alteration of wettability as well as that of permeability caused by sample firing. The dispersion profiles of the rock samples show that all samples are homogeneous.
