I. Oshilike, B. Mmata, P. Ugwu, Martins Otokpa, Chidinma Ibekwe, Okeke Hilary, M. Onyekonwu
Crude oil fingerprinting is a term applied to techniques that utilize geochemical analysis of hydrocarbon fluids composition to provide valuable information for well, reservoir and spill management. Analysis of crude oil fingerprints reveals a typical oil profile. Such a profile can provide information on formation history, type of carbon number preference during formation and route of migration. This study was undertaken using whole oil fingerprint and biomarkers of oils from twenty well strings from an onshore field in the Niger Delta Region. The aim was to evaluate light crude oils and determine thermal maturity, source rock quality, depositional environment and condensate correlation. The crude oil samples were analyzed using two major analytical techniques namely Gas Chromatography-Flame Ionization Detector (GC-FID) and Gas Chromatography-Mass Spectrometry (GC-MS). Evaluation of light hydrocarbon components was done using Mango parameters K1, K2, P2, P3 and N2 and the results revealed terrigenous organic matter input. Biomarker composition and pristane/phytane ratios in the range of 3.51 to 6.83 derived from GC results show that the source rock of the oils is made up of majorly terrestrial (type III) organic matter, deposited in a deltaic setting with prevailing oxic conditions. Maturity parameters calculated from Carbon Preference Indices between the range of 0.87 and 1.44 indicate the source is matured. The study provides key information on source characteristics that are applied to describe the type of petroleum prospects of a region. This study also provides information on condensate correlation, which has production implications such as application to production allocation.
{"title":"Fingerprint Analysis of Light Crude Oils from Niger Delta","authors":"I. Oshilike, B. Mmata, P. Ugwu, Martins Otokpa, Chidinma Ibekwe, Okeke Hilary, M. Onyekonwu","doi":"10.2118/212002-ms","DOIUrl":"https://doi.org/10.2118/212002-ms","url":null,"abstract":"\u0000 Crude oil fingerprinting is a term applied to techniques that utilize geochemical analysis of hydrocarbon fluids composition to provide valuable information for well, reservoir and spill management. Analysis of crude oil fingerprints reveals a typical oil profile. Such a profile can provide information on formation history, type of carbon number preference during formation and route of migration. This study was undertaken using whole oil fingerprint and biomarkers of oils from twenty well strings from an onshore field in the Niger Delta Region. The aim was to evaluate light crude oils and determine thermal maturity, source rock quality, depositional environment and condensate correlation. The crude oil samples were analyzed using two major analytical techniques namely Gas Chromatography-Flame Ionization Detector (GC-FID) and Gas Chromatography-Mass Spectrometry (GC-MS). Evaluation of light hydrocarbon components was done using Mango parameters K1, K2, P2, P3 and N2 and the results revealed terrigenous organic matter input. Biomarker composition and pristane/phytane ratios in the range of 3.51 to 6.83 derived from GC results show that the source rock of the oils is made up of majorly terrestrial (type III) organic matter, deposited in a deltaic setting with prevailing oxic conditions. Maturity parameters calculated from Carbon Preference Indices between the range of 0.87 and 1.44 indicate the source is matured. The study provides key information on source characteristics that are applied to describe the type of petroleum prospects of a region. This study also provides information on condensate correlation, which has production implications such as application to production allocation.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"44 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133064503","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The use of viscosity enhancer in Polymer flooding decreases mobility and improves sweep efficiency of flood water. However, there is a likelihood of permeability impairment due to the polymer retention onto the rock surface. This leads to formation damage. Therefore, a good assessment and evaluation of this problem is important to oil recovery sustenance. In this study, the permeability reduction caused by some local polymers in Nigeria used for Enhanced Oil Recovery was investigated. A laboratory study was carried out using unconsolidated core plugs (sands packs) and crude oil from the Niger Delta field. Two of the core plug samples (control samples) were flooded with simulated brine concentration and viscosity of 20000ppm and 0.949cP respectively. Cisus populnea (Okoho), Abelmoschus esculentus (Okro), Irvingia gabonensis (Ogbono) and Gum Arabic were used as polymers. Water breakthrough time, oil recovery and mobility ratio results obtained from fourteen samples were recorded and compared with that obtained from using only brine. The permeabilities of core plug samples were estimated prior to and after polymer flooding by pressure drop calculation. Residual Resistant Factor (RRF) and adsorption capacity of these polymers at same concentrations of 1000 ppm, 2500 ppm and 5000 ppm were also estimated. At 5000ppm, the RRF and mobility ratio for Cisus populnea, Abelmoschus esculentus, Gum Arabic and Irvingia gabonensis were 2.341/0.91., 1.354/0.35, 2567/0.56 and 3/0.66 respectively. The percentage reduction in permeability and displacement efficiency for Cisus populnea, Abelmoschus esculentus and Gum Arabic are 3.9%/75.30%, 2.7%/89.50% and 4.2%/77% respectively. It was observed that there was no-flow while flooding with Irvingia gabonensis at 5000ppm. The results from the study indicate that Irvingia gabonensis triggered the highest permeability impairment while Abelmoschus esculentus gave the least permeability impairment. The best performed polymer is Abelmoschus esculentus with highest displacement efficiency, reduced mobility ratio, lowest RRF values, lowest static and dynamic adsorption.
{"title":"Investigation of Permeability Impairment Using Local Polymers for Enhanced Oil Recovery","authors":"C. U. Uzoho, Enaanabhel Ade, M. Onyekonwu","doi":"10.2118/211922-ms","DOIUrl":"https://doi.org/10.2118/211922-ms","url":null,"abstract":"\u0000 The use of viscosity enhancer in Polymer flooding decreases mobility and improves sweep efficiency of flood water. However, there is a likelihood of permeability impairment due to the polymer retention onto the rock surface. This leads to formation damage. Therefore, a good assessment and evaluation of this problem is important to oil recovery sustenance. In this study, the permeability reduction caused by some local polymers in Nigeria used for Enhanced Oil Recovery was investigated. A laboratory study was carried out using unconsolidated core plugs (sands packs) and crude oil from the Niger Delta field. Two of the core plug samples (control samples) were flooded with simulated brine concentration and viscosity of 20000ppm and 0.949cP respectively. Cisus populnea (Okoho), Abelmoschus esculentus (Okro), Irvingia gabonensis (Ogbono) and Gum Arabic were used as polymers. Water breakthrough time, oil recovery and mobility ratio results obtained from fourteen samples were recorded and compared with that obtained from using only brine. The permeabilities of core plug samples were estimated prior to and after polymer flooding by pressure drop calculation. Residual Resistant Factor (RRF) and adsorption capacity of these polymers at same concentrations of 1000 ppm, 2500 ppm and 5000 ppm were also estimated. At 5000ppm, the RRF and mobility ratio for Cisus populnea, Abelmoschus esculentus, Gum Arabic and Irvingia gabonensis were 2.341/0.91., 1.354/0.35, 2567/0.56 and 3/0.66 respectively. The percentage reduction in permeability and displacement efficiency for Cisus populnea, Abelmoschus esculentus and Gum Arabic are 3.9%/75.30%, 2.7%/89.50% and 4.2%/77% respectively. It was observed that there was no-flow while flooding with Irvingia gabonensis at 5000ppm. The results from the study indicate that Irvingia gabonensis triggered the highest permeability impairment while Abelmoschus esculentus gave the least permeability impairment. The best performed polymer is Abelmoschus esculentus with highest displacement efficiency, reduced mobility ratio, lowest RRF values, lowest static and dynamic adsorption.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"116 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134097521","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the study of the dispersion modeling of accidental release of propane and butane using three locations in Lagos as case studies. The first case scenario was an actual incident while the other two were hypothetical case scenarios. In this research work, the purpose is to predict and evaluate the dispersion behaviour of the accidental releases of propane and butane using the Areal Location of Hazardous Atmosphere (ALOHA) modeling software, developed and made freely available by the US Environmental Protection Agency (EPA), along with Google Earth Pro mapping software which is also freely available. The modelling approach is applied to three (3) different study areas in Lagos: Propane Tanker along Iju Ishaga Road, Butane Cylindrical Tank at ABC Refilling Plant along Ikorodu Road and Butane Spherical Storage Tank at XYZGas Terminal in Apapa. The overall modelling study is concentrated on three (3) different hazardous scenarios of interest – flammable area of vapour cloud, blast area from vapour cloud explosion (uncongested) and blast area from vapour cloud explosion (congested). The flammability (flash fire) and overpressure (blast force) hazards considered in this study were modeled using the aforementioned free software. Primarily, the threat zones generated by ALOHA for separate scenarios were mapped on their respective location maps in order to evaluate the location of the dispersion plumes. For the hypothetical release scenarios considered, the dispersion modeling results showed that the Case 3 (XYZGas LPG Terminal in Apapa) has the most impacted areas for the red, orange and yellow threat zones with respect to buildings, institutions, shops, companies, streets, roads, etc. For the first study area, the results predicted the reported impact of the damaging effects for the Scenario C release. For the second study area, the results show that no threat zones are generated for the uncongested overpressure of Secnario B release. The kind of analysis and results obtained from this study would prove beneficial to the emergency planners and responders such as Lagos State Emergency Response Agency specialized in these study areas to help minimize the impacts of these dangerous releases and plan for safety decisions and mitigation techniques to be implemented where appropriate.
{"title":"Dispersion Modeling of Accidental Release of Propane and Butane: Case Studies of Some Locations in Lagos, Nigeria","authors":"Olumuyiwa M. Joseph, Almoruf O. F. Williams","doi":"10.2118/211935-ms","DOIUrl":"https://doi.org/10.2118/211935-ms","url":null,"abstract":"\u0000 This paper presents the study of the dispersion modeling of accidental release of propane and butane using three locations in Lagos as case studies. The first case scenario was an actual incident while the other two were hypothetical case scenarios. In this research work, the purpose is to predict and evaluate the dispersion behaviour of the accidental releases of propane and butane using the Areal Location of Hazardous Atmosphere (ALOHA) modeling software, developed and made freely available by the US Environmental Protection Agency (EPA), along with Google Earth Pro mapping software which is also freely available. The modelling approach is applied to three (3) different study areas in Lagos: Propane Tanker along Iju Ishaga Road, Butane Cylindrical Tank at ABC Refilling Plant along Ikorodu Road and Butane Spherical Storage Tank at XYZGas Terminal in Apapa. The overall modelling study is concentrated on three (3) different hazardous scenarios of interest – flammable area of vapour cloud, blast area from vapour cloud explosion (uncongested) and blast area from vapour cloud explosion (congested). The flammability (flash fire) and overpressure (blast force) hazards considered in this study were modeled using the aforementioned free software. Primarily, the threat zones generated by ALOHA for separate scenarios were mapped on their respective location maps in order to evaluate the location of the dispersion plumes. For the hypothetical release scenarios considered, the dispersion modeling results showed that the Case 3 (XYZGas LPG Terminal in Apapa) has the most impacted areas for the red, orange and yellow threat zones with respect to buildings, institutions, shops, companies, streets, roads, etc. For the first study area, the results predicted the reported impact of the damaging effects for the Scenario C release. For the second study area, the results show that no threat zones are generated for the uncongested overpressure of Secnario B release. The kind of analysis and results obtained from this study would prove beneficial to the emergency planners and responders such as Lagos State Emergency Response Agency specialized in these study areas to help minimize the impacts of these dangerous releases and plan for safety decisions and mitigation techniques to be implemented where appropriate.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"193 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131460941","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Rotimi, A. Akande, Betty Ihekona, Oseremen Iyamah, Somto Chukwuka, Yao Liang, Wang Zhenli, O. Ologe
This study attempts to estimate permeability from well logs data and also predict values from existing rock sections to points that are missing using Artificial Neural Network (ANN) and Sequential Gaussian Simulation (SGS). Potentially, exploration data is prone to trends that are initiated by the sedimentation process, but a detrending method using Semi-variogram (vertical) algorithm was applied to remove this from the interpreted wells which are all vertical. Permeability modeled for ANN gave an estimated root mean square error (RMSE) of 0.0449, while SGS gave RMSE of 0.1789, both giving a ‘K’ range of 100 – 1000 mD. Although the spatial geology of the area was relegated and not considered, making a spatial prediction influenced from the temporal reference point un-assessable. However, the independent prediction on the overall result shows a better prediction from the ANN, perhaps due to the optimization algorithm used.
{"title":"Comparative Study of Predictive Models for Permeability from Vertical wells using Sequential Gaussian Simulation and Artificial Neural Networks","authors":"O. Rotimi, A. Akande, Betty Ihekona, Oseremen Iyamah, Somto Chukwuka, Yao Liang, Wang Zhenli, O. Ologe","doi":"10.2118/211987-ms","DOIUrl":"https://doi.org/10.2118/211987-ms","url":null,"abstract":"\u0000 This study attempts to estimate permeability from well logs data and also predict values from existing rock sections to points that are missing using Artificial Neural Network (ANN) and Sequential Gaussian Simulation (SGS). Potentially, exploration data is prone to trends that are initiated by the sedimentation process, but a detrending method using Semi-variogram (vertical) algorithm was applied to remove this from the interpreted wells which are all vertical. Permeability modeled for ANN gave an estimated root mean square error (RMSE) of 0.0449, while SGS gave RMSE of 0.1789, both giving a ‘K’ range of 100 – 1000 mD. Although the spatial geology of the area was relegated and not considered, making a spatial prediction influenced from the temporal reference point un-assessable. However, the independent prediction on the overall result shows a better prediction from the ANN, perhaps due to the optimization algorithm used.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123889803","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Olugbenga Abolarin, Adetokunbo Ayodele, Bodunde Williams, Ikenna Pita-Nwana, C. Elendu
Growing concerns for global energy transition and dwindling demand for crude oil has impacted the revenues and investment portfolios of most oil and gas companies. More than ever, hydrocarbon exploration and production costs require extra scrutiny and prudence. Drilling and Completions costs take a significant proportion of the capital expenditure and savings realized from this would improve development cost per barrel, improve project economics and yield better returns for all stakeholders. To unlock the fiscal values required to win in this economic climate and attract investments to develop oil and gas assets, a paradigm shift is needed on well delivery, well design and execution processes. Cost savings opportunities exist all through the well maturation, but the highest value can be realized in the design stage. This stage involves opportunity identification, alternatives generation, setting of value based well objectives, design, and engineering etc. This paper discusses cost saving initiatives such as advanced casing design to optimize the number of casing strings run, slim well designs, streamlined formation evaluation plan, bottom hole assembly (BHA) optimization, equipment standardization, adoption of agile methodologies to determine minimum function objectives, utilization of data-analytics tools to drive performance, application of state-of-the-art technology, extensive use of peer assists and peer reviews etc. Proper adoption of these initiatives can yield up to 30% reduction in well cost and ultimately enable oil and gas companies to compete and win in any environment.
{"title":"Optimal Well Designs and Process Frameworks: Keys to Reducing Well Cost and Winning in any Environment","authors":"Olugbenga Abolarin, Adetokunbo Ayodele, Bodunde Williams, Ikenna Pita-Nwana, C. Elendu","doi":"10.2118/211909-ms","DOIUrl":"https://doi.org/10.2118/211909-ms","url":null,"abstract":"\u0000 Growing concerns for global energy transition and dwindling demand for crude oil has impacted the revenues and investment portfolios of most oil and gas companies. More than ever, hydrocarbon exploration and production costs require extra scrutiny and prudence. Drilling and Completions costs take a significant proportion of the capital expenditure and savings realized from this would improve development cost per barrel, improve project economics and yield better returns for all stakeholders.\u0000 To unlock the fiscal values required to win in this economic climate and attract investments to develop oil and gas assets, a paradigm shift is needed on well delivery, well design and execution processes. Cost savings opportunities exist all through the well maturation, but the highest value can be realized in the design stage. This stage involves opportunity identification, alternatives generation, setting of value based well objectives, design, and engineering etc.\u0000 This paper discusses cost saving initiatives such as advanced casing design to optimize the number of casing strings run, slim well designs, streamlined formation evaluation plan, bottom hole assembly (BHA) optimization, equipment standardization, adoption of agile methodologies to determine minimum function objectives, utilization of data-analytics tools to drive performance, application of state-of-the-art technology, extensive use of peer assists and peer reviews etc. Proper adoption of these initiatives can yield up to 30% reduction in well cost and ultimately enable oil and gas companies to compete and win in any environment.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"57 4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124483084","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Drilling for oil and gas wells is considered as a risk factor that is perceived as tolerable. As drilling companies expand into harsh environments and farther depth, the probability of a potential failure increases. An unexpected influx to or from the wellbore might be disastrous if not handled properly. Drilling-related issues such as jammed pipes, lost circulation, and high mud costs demonstrate the need for improved drilling technologies. The goal is to limit annular frictional pressure losses, especially in fields where the pore pressure and fracture pressure gradient are too close together. If these issues can be resolved, the economics of drilling wells would increase, allowing the industry to drill previously uneconomical wells. Managed Pressure Drilling (MPD) is a unique approach that allows the control of annular frictional pressure losses and can solve these types of drilling challenges. The industry is still mostly unaware of the entire range of advantages. Prompt detecting and handling of an influx of formation fluids can have the possibility to reduce the magnitude and extent of a kick by operating on a faster time scale with greater precision. Constant Bottomhole Pressure (CBHP), Pressurised Mudcap Drilling (PMCD), and Dual Gradient Drilling (DGD) are a few MPD variants. MPD reduces drilling issues and increases the economics of drilling wells. This research focuses on strategies employed in MPD, with the goal of uncovering some of the less well-known and thus underappreciated possibilities.
{"title":"A Method for Reducing Wellbore Instability Using the Managed Pressure Drilling (MPD) System","authors":"C. Ejike, T. Shouceng","doi":"10.2118/211902-ms","DOIUrl":"https://doi.org/10.2118/211902-ms","url":null,"abstract":"\u0000 Drilling for oil and gas wells is considered as a risk factor that is perceived as tolerable. As drilling companies expand into harsh environments and farther depth, the probability of a potential failure increases. An unexpected influx to or from the wellbore might be disastrous if not handled properly. Drilling-related issues such as jammed pipes, lost circulation, and high mud costs demonstrate the need for improved drilling technologies. The goal is to limit annular frictional pressure losses, especially in fields where the pore pressure and fracture pressure gradient are too close together. If these issues can be resolved, the economics of drilling wells would increase, allowing the industry to drill previously uneconomical wells. Managed Pressure Drilling (MPD) is a unique approach that allows the control of annular frictional pressure losses and can solve these types of drilling challenges. The industry is still mostly unaware of the entire range of advantages. Prompt detecting and handling of an influx of formation fluids can have the possibility to reduce the magnitude and extent of a kick by operating on a faster time scale with greater precision. Constant Bottomhole Pressure (CBHP), Pressurised Mudcap Drilling (PMCD), and Dual Gradient Drilling (DGD) are a few MPD variants. MPD reduces drilling issues and increases the economics of drilling wells. This research focuses on strategies employed in MPD, with the goal of uncovering some of the less well-known and thus underappreciated possibilities.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131755663","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper, the capacity of enzyme to influence brine-in-oil and oil-in-brine emulsions was investigated. The emulsion stability index method was used to monitor the effect of varied enzyme concentrations (1-, 5- and 10 wt.%) on oil-brine emulsion stability and separation process. The result of the study shows that the addition of different concentrations of enzyme to oil-brine mixtures enhanced the mixing and separation of the emulsions at varied capacities. Faster oil-brine separation was observed with increase in enzyme concentrations, but better mixing and higher emulsion stability was observed with lower concentration of enzyme. The result of this study is of a great significance to enzyme enhanced oil recovery application process in which good oil-brine mixture is require for the recovery of the residual oil saturation from the reservoir rock pores and the separation of oil and brine that is required after production at the surface.
{"title":"Investigation on Effect of Enzyme on Oil-Brine Emulsification","authors":"Tinuola Udoh, Osadebamen Aigbodion","doi":"10.2118/211906-ms","DOIUrl":"https://doi.org/10.2118/211906-ms","url":null,"abstract":"\u0000 In this paper, the capacity of enzyme to influence brine-in-oil and oil-in-brine emulsions was investigated. The emulsion stability index method was used to monitor the effect of varied enzyme concentrations (1-, 5- and 10 wt.%) on oil-brine emulsion stability and separation process. The result of the study shows that the addition of different concentrations of enzyme to oil-brine mixtures enhanced the mixing and separation of the emulsions at varied capacities. Faster oil-brine separation was observed with increase in enzyme concentrations, but better mixing and higher emulsion stability was observed with lower concentration of enzyme. The result of this study is of a great significance to enzyme enhanced oil recovery application process in which good oil-brine mixture is require for the recovery of the residual oil saturation from the reservoir rock pores and the separation of oil and brine that is required after production at the surface.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129959137","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sand production is of great concern in the Oil and Gas industry because of the economical, operational and technical problems that come with the phenomenon. Several sand prediction models are available in the literatures, but little or no consideration has been given to non-linearity of failure criterion used to develop the sand prediction models. Hence, a non-linear form of Mogi-Coulomb failure criterion was adopted in this research to develop a sand prediction model and simple sand prediction software. The most used rock failure criteria developed over the years for analyzing brittle failure of rocks is Mohr-Coulomb failure criterion. Published literatures have shown deficient in some field scenarios. Reason for these deficiencies was largely associated with the implicit assumption made in Mohr-Coulomb criterion that, the intermediate principal stress (σ2) has no influence on rock strength. So, this criterion is only based on the maximum and minimum principal stresses (σ1 and σ3) and only applicable to rock failure under conventional triaxial stress states (σ1 > σ2 = σ3). However, for a polyaxial stress state σ1 > σ2 > σ3), studies have proved that the intermediate principal stress (σ2) has a pronounced effect on rock strength and should not be neglected. Hence, Mohr–Coulomb criterion is relatively conservative in predicting sanding onset and therefore not very accurate for sand prediction models. As a result, this research presents a simple 3D sand prediction model based on Extended Mogi-Coulomb criterion that considered the non-linear relationships between most of field parameters when considering rock failure. The extended Mogi-Coulomb criterion is a nonlinear or parabolic form of Mogi-Coulomb criterion which accounts for the influence of the intermediate principal stress on rock strength and also very suitable for weak rocks. A fourth order polynomial equation was derived from first principle by combining both constitutive stress laws and the parabolic Mogi-Coulomb failure criterion. Then, Matlab software was used to develop a script and solution to the equation. And finally, the model solution was used to build simple graphic user interface software called ‘A.I Sand Predicton’ using Java programming language. Model verification was carried out by simulating several data available in the literatures and the solution was observed consistent with field observations. The solution of the critical wellbore pressure calculated using the "A.I Sand Predicton Software" was also found consistent with solution from Matlab and Mathematica softwares, respectively, which makes the software validated and reliable. Also, the case study shows that the critical wellbore pressure reduces as the strength parameters a, b, and c of the Extended Mogi-Coulomb criterion increases. Hence, the analytical model developed in this research using the extended Mogi-Coulomb criterion can reliably and accurately predict onset sand production.
{"title":"Modeling the Critical Pressure Below which Sand Production will Occur based on Extended Mogi-Coulomb Failure Criterion","authors":"Isaac Ajimosun, E. Okoro, Olafuyi Olalekan","doi":"10.2118/211953-ms","DOIUrl":"https://doi.org/10.2118/211953-ms","url":null,"abstract":"\u0000 Sand production is of great concern in the Oil and Gas industry because of the economical, operational and technical problems that come with the phenomenon. Several sand prediction models are available in the literatures, but little or no consideration has been given to non-linearity of failure criterion used to develop the sand prediction models. Hence, a non-linear form of Mogi-Coulomb failure criterion was adopted in this research to develop a sand prediction model and simple sand prediction software.\u0000 The most used rock failure criteria developed over the years for analyzing brittle failure of rocks is Mohr-Coulomb failure criterion. Published literatures have shown deficient in some field scenarios. Reason for these deficiencies was largely associated with the implicit assumption made in Mohr-Coulomb criterion that, the intermediate principal stress (σ2) has no influence on rock strength. So, this criterion is only based on the maximum and minimum principal stresses (σ1 and σ3) and only applicable to rock failure under conventional triaxial stress states (σ1 > σ2 = σ3). However, for a polyaxial stress state σ1 > σ2 > σ3), studies have proved that the intermediate principal stress (σ2) has a pronounced effect on rock strength and should not be neglected. Hence, Mohr–Coulomb criterion is relatively conservative in predicting sanding onset and therefore not very accurate for sand prediction models.\u0000 As a result, this research presents a simple 3D sand prediction model based on Extended Mogi-Coulomb criterion that considered the non-linear relationships between most of field parameters when considering rock failure. The extended Mogi-Coulomb criterion is a nonlinear or parabolic form of Mogi-Coulomb criterion which accounts for the influence of the intermediate principal stress on rock strength and also very suitable for weak rocks. A fourth order polynomial equation was derived from first principle by combining both constitutive stress laws and the parabolic Mogi-Coulomb failure criterion. Then, Matlab software was used to develop a script and solution to the equation. And finally, the model solution was used to build simple graphic user interface software called ‘A.I Sand Predicton’ using Java programming language. Model verification was carried out by simulating several data available in the literatures and the solution was observed consistent with field observations. The solution of the critical wellbore pressure calculated using the \"A.I Sand Predicton Software\" was also found consistent with solution from Matlab and Mathematica softwares, respectively, which makes the software validated and reliable. Also, the case study shows that the critical wellbore pressure reduces as the strength parameters a, b, and c of the Extended Mogi-Coulomb criterion increases. Hence, the analytical model developed in this research using the extended Mogi-Coulomb criterion can reliably and accurately predict onset sand production.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123379579","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. K. Ihekoronye, H. Mohammed, Pius Chukwuebuka Onuorah
This research work focuses on the performance of sodium lauryl sulfate as surfactant in enhanced oil recovery of medium crude oil in the Niger Delta fields. Characterization of the sodium lauryl sulfate (surfactant) was carried out to determine the functional groups and morphology of the sample. Different tests such as interfacial tension reduction and adsorption test were conducted to evaluate the effectiveness of the sample in enhanced oil recovery. Core-flooding experiment was performed using the sample to determine the potency of sodium lauryl sulfate in enhanced oil recovery process. The results from this work showed that incremental oil recoveries of 47.8 %, 54.6 % and 56.1 % using Berea core sample (C1F) and 49.3 %, 57.6 % and 58.5 % for core sample (C2F) was observed. The results showed that sodium lauryl sulfate achieve macroscopic sweep displacement efficiency via interfacial tension reduction between the surfactant slugs and the trapped oil which helps to improve oil production.
{"title":"Application of Sodium Lauryl Sulfate for Enhanced Oil Recovery of Medium Crude Oil in the Niger Delta Fields","authors":"K. K. Ihekoronye, H. Mohammed, Pius Chukwuebuka Onuorah","doi":"10.2118/211978-ms","DOIUrl":"https://doi.org/10.2118/211978-ms","url":null,"abstract":"\u0000 This research work focuses on the performance of sodium lauryl sulfate as surfactant in enhanced oil recovery of medium crude oil in the Niger Delta fields. Characterization of the sodium lauryl sulfate (surfactant) was carried out to determine the functional groups and morphology of the sample. Different tests such as interfacial tension reduction and adsorption test were conducted to evaluate the effectiveness of the sample in enhanced oil recovery. Core-flooding experiment was performed using the sample to determine the potency of sodium lauryl sulfate in enhanced oil recovery process. The results from this work showed that incremental oil recoveries of 47.8 %, 54.6 % and 56.1 % using Berea core sample (C1F) and 49.3 %, 57.6 % and 58.5 % for core sample (C2F) was observed. The results showed that sodium lauryl sulfate achieve macroscopic sweep displacement efficiency via interfacial tension reduction between the surfactant slugs and the trapped oil which helps to improve oil production.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"68 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129493620","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Idahosa Ehibor, I. Ohenhen, Bukolo Oloyede, Gbenga Adetoyi, Tochukwu Amaechi, Olanike Olajide, A. Kaka, Anthony Woyengidiripre
Gas condensate banking accumulated near the wellbore occurs when the bottomhole pressure becomes less than the dew point pressure, allowing the liquid fraction to condense out of the gas phase. Once the accumulation near the wellbore is higher than critical condensate saturation, the liquid phase becomes mobile with the gas phase, affecting well deliverability and making it difficult to estimate gas and condensate flow rate from the reservoir due to two phase flow of fluid. This paper presents an analytical model that evaluates the well deliverability from the reservoir. The concept of two phases Pseudo-pressure is used in the interpretation and evaluation of well deliverability from the gas condensate reservoir. The model considers non-Darcy flow effects and capillary effects. The model is applied to a live field case study of a Niger Delta gas condensate reservoir to determine well deliverability. Gas and liquid production profile from the model showed 95% accuracy when compared with compositional simulation model. This model is encoded into a spreadsheet program using python to calculate well deliverability parameters.
{"title":"Gas Condensate Well Deliverability Model, a Field Case Study of a Niger Delta Gas Condensate Reservoir","authors":"Idahosa Ehibor, I. Ohenhen, Bukolo Oloyede, Gbenga Adetoyi, Tochukwu Amaechi, Olanike Olajide, A. Kaka, Anthony Woyengidiripre","doi":"10.2118/212043-ms","DOIUrl":"https://doi.org/10.2118/212043-ms","url":null,"abstract":"\u0000 Gas condensate banking accumulated near the wellbore occurs when the bottomhole pressure becomes less than the dew point pressure, allowing the liquid fraction to condense out of the gas phase. Once the accumulation near the wellbore is higher than critical condensate saturation, the liquid phase becomes mobile with the gas phase, affecting well deliverability and making it difficult to estimate gas and condensate flow rate from the reservoir due to two phase flow of fluid. This paper presents an analytical model that evaluates the well deliverability from the reservoir.\u0000 The concept of two phases Pseudo-pressure is used in the interpretation and evaluation of well deliverability from the gas condensate reservoir. The model considers non-Darcy flow effects and capillary effects.\u0000 The model is applied to a live field case study of a Niger Delta gas condensate reservoir to determine well deliverability. Gas and liquid production profile from the model showed 95% accuracy when compared with compositional simulation model. This model is encoded into a spreadsheet program using python to calculate well deliverability parameters.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"6 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113963640","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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