The Total petroleum hydrocarbon (TPH) of water contaminated with Bonny Light crude oil was determined before and after absorption using Ultraviolet (UV) spectroscopy and Gas Chromatographic (GC) analyses. Shells of periwinkle, thales (ngolo) and oyster were used as absorbents, each of the shells were ground into powdery form, sieved through a mesh of 50 microns and calcined at temperatures of 500, 600 and 700°C respectively. Results obtained from UV spectroscopic analyses showed that the TPH concentration of the oil contaminated water after absorption with uncalcined periwinkle, thales and oyster shells were 1410.0, 1371.0 and 1330.0 mg/l respectively. The higher the calcination temperature of the absorbents, the lower the TPH of the oil contaminated water after absorption making oyster shell calcined at 700°C the best absorbent. GC analyses gave the individual hydrocarbon components of the oil contaminated water before and after absorption thereby confirming the uptake efficiencies of the absorbents. The lower the TPH of the oil contaminated water, the higher the uptake efficiency of the absorbents which is directly proportional to the dilution factor and the amount of crude absorbed by the absorbents. The uptake efficiency of the absorbents follows the trend Oyster >thales> periwinkle. The process of calcination (high temperature heating) boosted the uptake efficiency of the absorbents by 45 percent.
{"title":"Absorption of Crude Oil from Water Surface Using Shells of Periwinkle, Thales (Ngolo) and Oyster","authors":"Osuji Lc","doi":"10.23880/ppej-16000392","DOIUrl":"https://doi.org/10.23880/ppej-16000392","url":null,"abstract":"The Total petroleum hydrocarbon (TPH) of water contaminated with Bonny Light crude oil was determined before and after absorption using Ultraviolet (UV) spectroscopy and Gas Chromatographic (GC) analyses. Shells of periwinkle, thales (ngolo) and oyster were used as absorbents, each of the shells were ground into powdery form, sieved through a mesh of 50 microns and calcined at temperatures of 500, 600 and 700°C respectively. Results obtained from UV spectroscopic analyses showed that the TPH concentration of the oil contaminated water after absorption with uncalcined periwinkle, thales and oyster shells were 1410.0, 1371.0 and 1330.0 mg/l respectively. The higher the calcination temperature of the absorbents, the lower the TPH of the oil contaminated water after absorption making oyster shell calcined at 700°C the best absorbent. GC analyses gave the individual hydrocarbon components of the oil contaminated water before and after absorption thereby confirming the uptake efficiencies of the absorbents. The lower the TPH of the oil contaminated water, the higher the uptake efficiency of the absorbents which is directly proportional to the dilution factor and the amount of crude absorbed by the absorbents. The uptake efficiency of the absorbents follows the trend Oyster >thales> periwinkle. The process of calcination (high temperature heating) boosted the uptake efficiency of the absorbents by 45 percent.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"50 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141841462","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}
Development of petroleum marginal fields has inevitable become a crucial due to the continuous production decrease in mature and large fields. Although they may not have huge resources, they still can be economically developed and exploited using the available current technologies. Then, they will substitute the lackage of other sources of energy. Therefore, this paper's primary goal is to explore and develop Nigeria's marginal oil and gas reserves, one of which had a blowout during the process of reopening and developing. Nigerian offshore marginal gas condensate field with a blowout well called ‘’Well-1’’ is studied. Three approaches are firstly proposed in order to control and re-entry Well-1. Field development and evaluation were performed. Studies and analyses carried out on the marginal field, which is a gas condensate reservoir, showed valuable reserves. Also, a sensitivity study was done for various recovery factors that could be achieved during producing from the reservoir for each zone and for the total reserves. Afterthat, a cost study was done with changing the interest rate for the next five years. Plans, developments, policies and strategies that have been explored, marginal fields, and completed work are all assessed. Furthermore, gas field development and processing scheme were done and suggested. A thorough discussion and recommendation of problem-solving strategies, technologies, scientific methodologies, and simulation studies were provided. Finally, the situation of marginal fields in Romania is reviewed to know at which level is the development stage. Taken decisions, strategies and polices of the companies owned these fields are also presented. Recommendations to develop those fields are obviously presented.
{"title":"Exploitation and Development of Oil/Gas Marginal Fields in Nigeria and Romania: Technology, Rising Market Development Challenges & Sustainable Energy Transition","authors":"Halafawi M","doi":"10.23880/ppej-16000391","DOIUrl":"https://doi.org/10.23880/ppej-16000391","url":null,"abstract":"Development of petroleum marginal fields has inevitable become a crucial due to the continuous production decrease in mature and large fields. Although they may not have huge resources, they still can be economically developed and exploited using the available current technologies. Then, they will substitute the lackage of other sources of energy. Therefore, this paper's primary goal is to explore and develop Nigeria's marginal oil and gas reserves, one of which had a blowout during the process of reopening and developing. Nigerian offshore marginal gas condensate field with a blowout well called ‘’Well-1’’ is studied. Three approaches are firstly proposed in order to control and re-entry Well-1. Field development and evaluation were performed. Studies and analyses carried out on the marginal field, which is a gas condensate reservoir, showed valuable reserves. Also, a sensitivity study was done for various recovery factors that could be achieved during producing from the reservoir for each zone and for the total reserves. Afterthat, a cost study was done with changing the interest rate for the next five years. Plans, developments, policies and strategies that have been explored, marginal fields, and completed work are all assessed. Furthermore, gas field development and processing scheme were done and suggested. A thorough discussion and recommendation of problem-solving strategies, technologies, scientific methodologies, and simulation studies were provided. Finally, the situation of marginal fields in Romania is reviewed to know at which level is the development stage. Taken decisions, strategies and polices of the companies owned these fields are also presented. Recommendations to develop those fields are obviously presented.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"1977 11‐12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141852098","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 the context of developing multilayer deposits in Turkmenistan, the technical and economic evaluation of technique used in simultaneous and independent operation represents an important area of work. Most of the oil and gas fields both in our country and abroad are multi-layered. At the same time, several productive layers are located layer by layer one above the other. From the point of view of rational development, the development of such deposits by independent grids of wells drilled for each individual reservoir is the most preferable. However, the experience of oilfield development shows that more than half of all capital investments are spent on drilling wells. Therefore, the development of multilayer deposits by independent well grids for each formation requires huge capital expenditures and is not always economically and technologically justified. In this regard, when developing multi-layer deposits, several productive formations are often combined into one operational facility, which makes it possible to shorten the time of field development, reduce capital investments for drilling wells and field development, etc. At the same time, simultaneous development of several formations by one object is possible only with the same physico-chemical properties of oils in the combined formations, if the inflow of oil and gas is sufficient from each formation at an acceptable bottom-hole pressure in the well, with close values of reservoir pressure in the combined formations, excluding oil flows between the formations, and close values of reservoir waterlogging. If the above conditions are not met, then multidimensional deposits are developed using the method of simultaneous and independent operation (hereinafter referred to as SIO) with one well. Depending on the specific geological and technical conditions for the development of deposits, technical and operational characteristics of wells, one of the currently available SIO schemes is used. Mandatory requirements for all SIO schemes are the possibility of separate development and commissioning of each reservoir, measurement of oil flow rates of each reservoir separately, as well as separate measurement of each reservoir for waterlogging, gas content and examination of each reservoir for oil and gas inflow. When deciding on the use of the SIO method, the degree of depletion of reserves, the proximity of the oil content contour to wells, the presence of resins and paraffin in the extracted oils, the thickness of the productive layers and the impermeable interlayers separating them, the condition of the production column of wells, etc. Productive horizons have different capacities from one to several tens of meters; their operation is carried out from the bottom up according to the traditional scheme. Such a traditional scheme of operation of multilayer deposits provides for the development of a grid of vertical wells for each operational facility, which leads to an increase in capital costs for dr
{"title":"Review of the Technical and Economic Evaluation of the Use of Means of Simultaneous Independent Operation for Solving Technical Problems","authors":"Deryaev A","doi":"10.23880/ppej-16000385","DOIUrl":"https://doi.org/10.23880/ppej-16000385","url":null,"abstract":"In the context of developing multilayer deposits in Turkmenistan, the technical and economic evaluation of technique used in simultaneous and independent operation represents an important area of work. Most of the oil and gas fields both in our country and abroad are multi-layered. At the same time, several productive layers are located layer by layer one above the other. From the point of view of rational development, the development of such deposits by independent grids of wells drilled for each individual reservoir is the most preferable. However, the experience of oilfield development shows that more than half of all capital investments are spent on drilling wells. Therefore, the development of multilayer deposits by independent well grids for each formation requires huge capital expenditures and is not always economically and technologically justified. In this regard, when developing multi-layer deposits, several productive formations are often combined into one operational facility, which makes it possible to shorten the time of field development, reduce capital investments for drilling wells and field development, etc. At the same time, simultaneous development of several formations by one object is possible only with the same physico-chemical properties of oils in the combined formations, if the inflow of oil and gas is sufficient from each formation at an acceptable bottom-hole pressure in the well, with close values of reservoir pressure in the combined formations, excluding oil flows between the formations, and close values of reservoir waterlogging. If the above conditions are not met, then multidimensional deposits are developed using the method of simultaneous and independent operation (hereinafter referred to as SIO) with one well. Depending on the specific geological and technical conditions for the development of deposits, technical and operational characteristics of wells, one of the currently available SIO schemes is used. Mandatory requirements for all SIO schemes are the possibility of separate development and commissioning of each reservoir, measurement of oil flow rates of each reservoir separately, as well as separate measurement of each reservoir for waterlogging, gas content and examination of each reservoir for oil and gas inflow. When deciding on the use of the SIO method, the degree of depletion of reserves, the proximity of the oil content contour to wells, the presence of resins and paraffin in the extracted oils, the thickness of the productive layers and the impermeable interlayers separating them, the condition of the production column of wells, etc. Productive horizons have different capacities from one to several tens of meters; their operation is carried out from the bottom up according to the traditional scheme. Such a traditional scheme of operation of multilayer deposits provides for the development of a grid of vertical wells for each operational facility, which leads to an increase in capital costs for dr","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"11 16","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140745582","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 Middle East, rich in oil and gas within carbonate rocks, accounts for a significant portion of global reserves, drawing extensive exploration by major oil firms. Unlike Southeast Asia's fracture and cavity-dominated carbonate reservoirs, the Middle East features thick-bedded, pore-structured reservoirs with vast reserves. These complex and varied pore structures cause reservoir inhomogeneity, challenging the technical evaluation of these unconventional reservoirs. Characterization of carbonate reservoirs differs in terms of their mineralogical compositions and heterogenous pore systems from that of clastic reservoirs. Reservoir characterization seeks to build geological and petrophysical models for reservoir simulation. Rock types represent the most crucial characteristics of reservoirs for specialized facies modelling within specific ranges of porosity and permeability. Rock typing is an essential method routinely used by petroleum engineers for characterizing and predicting the reservoir quality of carbonate reservoirs by classifying reservoir rocks into distinct units based on similar petrophysical properties. It is imperative to predict these reservoir properties accurately and precisely. The J-function technique is considered the most effective rock typing procedure. In this study, a new correlation for predicting initial water saturation (Swi) for a reservoir producing from a Permian carbonate formation, located in the Arabian Peninsula, has been developed. The new empirical equation is an augmented Lucia model that utilizes capillary pressure (P�), porosity (), and permeability (k), as independent variables. The coefficient of multiple R2 , the student’s t and F-tests p-value were used in the model evaluation. R2 for the new model was about 0.92, t-test and F-test p-values were much lower than 0.05, indicating that the independent variables are significant. The model was also tested against an independent data set and yielded an R2 of 0.88. Likewise, the new correlation was compared to Lucia’s model and showed better results. The goal of the study is to use the developed correlation in the geostatistical modeling of connate water saturation for analogous formations in the region.
中东地区的碳酸盐岩中蕴藏着丰富的石油和天然气，占全球储量的很大一部分，吸引着大型石油公司进行广泛勘探。与东南亚以裂缝和空洞为主的碳酸盐岩储层不同，中东地区以厚层、孔隙结构储层为特色，储量巨大。这些复杂多变的孔隙结构造成储层的不均匀性，给这些非常规储层的技术评估带来了挑战。碳酸盐岩储层的特征描述在矿物组成和异质孔隙系统方面与碎屑岩储层不同。储层特征描述旨在为储层模拟建立地质和岩石物理模型。岩石类型代表了储层最关键的特征，用于在特定的孔隙度和渗透率范围内建立专门的储层面模型。岩石类型学是石油工程师在描述和预测碳酸盐岩储层质量时经常使用的一种重要方法，它根据相似的岩石物理特性将储层岩石划分为不同的单元。必须准确和精确地预测这些储层属性。J 函数技术被认为是最有效的岩石分型程序。本研究开发了一种新的相关方法，用于预测阿拉伯半岛二叠纪碳酸盐岩层储层的初始含水饱和度（Swi）。新的经验方程是一个增强的 Lucia 模型，利用毛细管压力 (P�)、孔隙度 () 和渗透率 (k) 作为自变量。模型评估采用了多重 R2 系数、学生 t 和 F 检验 p 值。新模型的 R2 约为 0.92，t 检验和 F 检验的 p 值远小于 0.05，表明自变量是显著的。该模型还根据独立数据集进行了测试，R2 为 0.88。同样，新的相关性也与 Lucia 的模型进行了比较，结果显示更好。该研究的目标是将开发的相关性用于该地区类似地层的涵养水饱和度地质统计建模。
{"title":"Development of a New Correlation for Predicting Initial Water Saturation in Carbonate Reservoirs","authors":"Edusah E","doi":"10.23880/ppej-16000384","DOIUrl":"https://doi.org/10.23880/ppej-16000384","url":null,"abstract":"The Middle East, rich in oil and gas within carbonate rocks, accounts for a significant portion of global reserves, drawing extensive exploration by major oil firms. Unlike Southeast Asia's fracture and cavity-dominated carbonate reservoirs, the Middle East features thick-bedded, pore-structured reservoirs with vast reserves. These complex and varied pore structures cause reservoir inhomogeneity, challenging the technical evaluation of these unconventional reservoirs. Characterization of carbonate reservoirs differs in terms of their mineralogical compositions and heterogenous pore systems from that of clastic reservoirs. Reservoir characterization seeks to build geological and petrophysical models for reservoir simulation. Rock types represent the most crucial characteristics of reservoirs for specialized facies modelling within specific ranges of porosity and permeability. Rock typing is an essential method routinely used by petroleum engineers for characterizing and predicting the reservoir quality of carbonate reservoirs by classifying reservoir rocks into distinct units based on similar petrophysical properties. It is imperative to predict these reservoir properties accurately and precisely. The J-function technique is considered the most effective rock typing procedure. In this study, a new correlation for predicting initial water saturation (Swi) for a reservoir producing from a Permian carbonate formation, located in the Arabian Peninsula, has been developed. The new empirical equation is an augmented Lucia model that utilizes capillary pressure (P�), porosity (), and permeability (k), as independent variables. The coefficient of multiple R2 , the student’s t and F-tests p-value were used in the model evaluation. R2 for the new model was about 0.92, t-test and F-test p-values were much lower than 0.05, indicating that the independent variables are significant. The model was also tested against an independent data set and yielded an R2 of 0.88. Likewise, the new correlation was compared to Lucia’s model and showed better results. The goal of the study is to use the developed correlation in the geostatistical modeling of connate water saturation for analogous formations in the region.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"11 18","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140744188","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}
CO2 emissions rates have seen an exponential growth from the 19th century up till date, if no drastic measures and plans are implemented to prevent this exponential growth the consequence will be devastating. The notion of achieving net-zero greenhouse gas emissions gained prominence through the Paris Agreement, a groundbreaking accord reached at the United Nations Climate Change Conference. This agreement was devised to mitigate the impact of greenhouse gas emissions. To execute the net-zero CO2 emission plan, the USDOE has set a new goal to remove gigatons of carbon dioxide (CO2 ) from the atmosphere and durably store it for less than $100/ton of net CO2 -equivalent. Making such a goal a reality requires an accurate estimation of CO2 storage capacity for the successful implementation of Carbon Capture and Storage (CCS) technologies, and the assessment of the impact of CCS to the reduction of CO2 emissions. Hence this paper serves as a template for accurately estimating CO2 storage capacity in depleted saturated oil reservoirs with initial gas cap using three approaches: Volumetric, Production and Correlation-based methods and compares the accuracy of the estimates. A case study was conducted on a depleted VR273_Q combination sand in the Vermillion Basin, Gulf of Mexico (GOM). The deterministic and stochastic (P50) CO2 storage capacity estimates from the Volume-based method are 1.21 million tonnes (Mt) and 1.23 Mt respectively, while the deterministic CO2 storage capacity estimates from the Production and Correlationbased method are 1.32 Mt and 1.41 Mt respectively. All three approaches showed similar results, with little deviations attributed to petrophysical uncertainties arising from data gaps i.e., absence of well logs to key wells. However, these uncertainties are captured by Stochastic (P90) CO2 storage capacity estimates of 1.47 Mt from the Volume-based method. Although the Correlation-based approach slightly overestimates the CO2 storage capacity, it can be used as a starting point for quick estimation as it only requires production data which are readily available on various databases for GOM. Finally, through this paper, opportunities for concerned agencies to make well-informed energy-related policies and business decisions are made possible.
{"title":"Comparative Study of CO2 Storage Capacity Estimation in Depleted Oil & Gas Reservoir: A Case Study in Vermillion Basin Gulf of Mexico","authors":"Ighomuaye E","doi":"10.23880/ppej-16000379","DOIUrl":"https://doi.org/10.23880/ppej-16000379","url":null,"abstract":"CO2 emissions rates have seen an exponential growth from the 19th century up till date, if no drastic measures and plans are implemented to prevent this exponential growth the consequence will be devastating. The notion of achieving net-zero greenhouse gas emissions gained prominence through the Paris Agreement, a groundbreaking accord reached at the United Nations Climate Change Conference. This agreement was devised to mitigate the impact of greenhouse gas emissions. To execute the net-zero CO2 emission plan, the USDOE has set a new goal to remove gigatons of carbon dioxide (CO2 ) from the atmosphere and durably store it for less than $100/ton of net CO2 -equivalent. Making such a goal a reality requires an accurate estimation of CO2 storage capacity for the successful implementation of Carbon Capture and Storage (CCS) technologies, and the assessment of the impact of CCS to the reduction of CO2 emissions. Hence this paper serves as a template for accurately estimating CO2 storage capacity in depleted saturated oil reservoirs with initial gas cap using three approaches: Volumetric, Production and Correlation-based methods and compares the accuracy of the estimates. A case study was conducted on a depleted VR273_Q combination sand in the Vermillion Basin, Gulf of Mexico (GOM). The deterministic and stochastic (P50) CO2 storage capacity estimates from the Volume-based method are 1.21 million tonnes (Mt) and 1.23 Mt respectively, while the deterministic CO2 storage capacity estimates from the Production and Correlationbased method are 1.32 Mt and 1.41 Mt respectively. All three approaches showed similar results, with little deviations attributed to petrophysical uncertainties arising from data gaps i.e., absence of well logs to key wells. However, these uncertainties are captured by Stochastic (P90) CO2 storage capacity estimates of 1.47 Mt from the Volume-based method. Although the Correlation-based approach slightly overestimates the CO2 storage capacity, it can be used as a starting point for quick estimation as it only requires production data which are readily available on various databases for GOM. Finally, through this paper, opportunities for concerned agencies to make well-informed energy-related policies and business decisions are made possible.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"18 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140498734","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}
Heavy oil reservoirs often lend themselves well to thermal enhanced recovery techniques. Traditional methods like primary production or water injection are less effective due to the high viscosity of the oil. Steam stimulation primarily aims to elevate the reservoir's temperature, thereby reducing the oil's viscosity and improving its flow properties. Steam injection stands as one of the most prevalent thermal recovery methods, commonly applied in heavy oil reservoirs. The primary goal is to validate the process for selecting suitable reservoirs, the physical mechanisms involved, and the simulation characteristics essential for steam recovery. This study establishes the optimal multiplier for reducing oil viscosity and the ideal steam injection rate for heavy oil fields.
{"title":"Defining the Ideal Range for Reducing Oil Viscosity and the Optimal Rate of Steam Injection for a Heavy Oil Field","authors":"Jafarov S","doi":"10.23880/ppej-16000381","DOIUrl":"https://doi.org/10.23880/ppej-16000381","url":null,"abstract":"Heavy oil reservoirs often lend themselves well to thermal enhanced recovery techniques. Traditional methods like primary production or water injection are less effective due to the high viscosity of the oil. Steam stimulation primarily aims to elevate the reservoir's temperature, thereby reducing the oil's viscosity and improving its flow properties. Steam injection stands as one of the most prevalent thermal recovery methods, commonly applied in heavy oil reservoirs. The primary goal is to validate the process for selecting suitable reservoirs, the physical mechanisms involved, and the simulation characteristics essential for steam recovery. This study establishes the optimal multiplier for reducing oil viscosity and the ideal steam injection rate for heavy oil fields.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"15 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140499244","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 a previous study, wellbore cleaning coefficient (WCC) correlations for cleaned wellbores out of debris and bridge plug remnants were developed for three conventional coiled tubing sizes (2.375”, 2.625”, and 2.875”). The following key performance indicators (KPIs): (1) slick water density ( ) ρ f , (2) slick water viscosity ( ) µ f , (3) hydraulic diameter c t (d - d ) between casing inner diameter (dc ) and coil tubing outer diameter (dt ), (4) average annular velocity ( ) v and (5) cleaning pressure gradient ∆P across a measured depth (MD) were employed in the empirical models. The models addressed operational conditions under which fractured wells will be identified as whether “clean” or “not clean”. In this study, the database from 150 wells, in the Spraberry formation in West Texas, was used to develop a predictive model to identify status of cleaned fractured wells: whether “clean” or “not clean”? About 70% of the data (99 wells) was used for training and about 30% (51 wells) for validation. 14 wells from the liquids-rich shale Woodford formation (Oklahoma) were utilized for testing. Six predictive modeling tools were designed to validate the derived empirical correlations. These tools are (1) Fit Stepwise, (2) Neural Boosted, (3) Boosted Tree, (4) Decision Tree (Partition), (5) Generalized Regression Lasso, and K-Nearest Neighbors. In the predictive models, independent variables are the annular velocity (AV), the Reynolds’ Number (Re), the Euler’s Number (Eu), and the coiled tubing roughness to internal radius ratio (ε/D). The dependent variable is well status; “clean” or “not clean”. Jump Scripting Language (JSL) code was used to develop user-friendly software. The software would be utilized to identify the fractured wellbore status, whether “clean” or “not clean”. Operators would be able to use the code to identify working conditions for which completed fractured wells are “clean” out of fracturing debris and remnants of bridge plugs or “not clean”. Input parameters to the code are AV, Re, Eu, and ε/D
{"title":"Development of A Neural Boosted Model and JSL Code to Identify “Clean” or “Not Clean” Wells - A West Texas Sperry and Oklahoma Woodford Fractured Wells Coiled Tubing Cleaning Case Study","authors":"Trabelsi H","doi":"10.23880/ppej-16000377","DOIUrl":"https://doi.org/10.23880/ppej-16000377","url":null,"abstract":"In a previous study, wellbore cleaning coefficient (WCC) correlations for cleaned wellbores out of debris and bridge plug remnants were developed for three conventional coiled tubing sizes (2.375”, 2.625”, and 2.875”). The following key performance indicators (KPIs): (1) slick water density ( ) ρ f , (2) slick water viscosity ( ) µ f , (3) hydraulic diameter c t (d - d ) between casing inner diameter (dc ) and coil tubing outer diameter (dt ), (4) average annular velocity ( ) v and (5) cleaning pressure gradient ∆P across a measured depth (MD) were employed in the empirical models. The models addressed operational conditions under which fractured wells will be identified as whether “clean” or “not clean”. In this study, the database from 150 wells, in the Spraberry formation in West Texas, was used to develop a predictive model to identify status of cleaned fractured wells: whether “clean” or “not clean”? About 70% of the data (99 wells) was used for training and about 30% (51 wells) for validation. 14 wells from the liquids-rich shale Woodford formation (Oklahoma) were utilized for testing. Six predictive modeling tools were designed to validate the derived empirical correlations. These tools are (1) Fit Stepwise, (2) Neural Boosted, (3) Boosted Tree, (4) Decision Tree (Partition), (5) Generalized Regression Lasso, and K-Nearest Neighbors. In the predictive models, independent variables are the annular velocity (AV), the Reynolds’ Number (Re), the Euler’s Number (Eu), and the coiled tubing roughness to internal radius ratio (ε/D). The dependent variable is well status; “clean” or “not clean”. Jump Scripting Language (JSL) code was used to develop user-friendly software. The software would be utilized to identify the fractured wellbore status, whether “clean” or “not clean”. Operators would be able to use the code to identify working conditions for which completed fractured wells are “clean” out of fracturing debris and remnants of bridge plugs or “not clean”. Input parameters to the code are AV, Re, Eu, and ε/D","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"66 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140498677","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 study addresses the pressing demand for streamlined field performance analysis within oil and natural gas development, which currently necessitates substantial expertise and time investment. The principal aim involves developing a user-friendly software tool dedicated to optimizing reservoir rendition. Leveraging the Havlena and Odeh material balance straight line equation form, this tool integrates a zero-dimensional reservoir model with Decline Curve Analysis. The implementation of this user-friendly software enables achievable material balance optimization by aligning cumulative produced fluid with historical production data, akin to the widely acknowledged concept of history matching in material balance analysis. This accomplishment not only facilitates further endeavors like pressure simulation and forecasting but also augments the comprehension of reservoir dynamics. The analysis incorporated three datasets: one modeled from L.P. Dake's textbook and two drawn from real-life reservoirs in the Niger Delta. Assessment of estimated water influx and cumulative oil production indicated minimal discrepancies between Np Real and Np model for these reservoirs. Consequently, material balance history matching for these reservoirs seems feasible. Achieving reservoir rendition optimization involved a Microsoft Excel VBA code consisting of two hundred and thirty-five (235) lines, meticulously designed to replicate MBAL functionality. The software demonstrated congruent outcomes with MBAL, affirming its reliability for history matching and enhancing reservoir performance. We strongly advocate the utilization of this software for optimizing reservoir performance across diverse global regions. Its capacity to streamline field analysis could significantly benefit the oil and natural gas industry.
{"title":"Advancing Reservoir Performance Optimization through UserFriendly Excel VBA Software Development","authors":"Ebere Fo","doi":"10.23880/ppej-16000374","DOIUrl":"https://doi.org/10.23880/ppej-16000374","url":null,"abstract":"This study addresses the pressing demand for streamlined field performance analysis within oil and natural gas development, which currently necessitates substantial expertise and time investment. The principal aim involves developing a user-friendly software tool dedicated to optimizing reservoir rendition. Leveraging the Havlena and Odeh material balance straight line equation form, this tool integrates a zero-dimensional reservoir model with Decline Curve Analysis. The implementation of this user-friendly software enables achievable material balance optimization by aligning cumulative produced fluid with historical production data, akin to the widely acknowledged concept of history matching in material balance analysis. This accomplishment not only facilitates further endeavors like pressure simulation and forecasting but also augments the comprehension of reservoir dynamics. The analysis incorporated three datasets: one modeled from L.P. Dake's textbook and two drawn from real-life reservoirs in the Niger Delta. Assessment of estimated water influx and cumulative oil production indicated minimal discrepancies between Np Real and Np model for these reservoirs. Consequently, material balance history matching for these reservoirs seems feasible. Achieving reservoir rendition optimization involved a Microsoft Excel VBA code consisting of two hundred and thirty-five (235) lines, meticulously designed to replicate MBAL functionality. The software demonstrated congruent outcomes with MBAL, affirming its reliability for history matching and enhancing reservoir performance. We strongly advocate the utilization of this software for optimizing reservoir performance across diverse global regions. Its capacity to streamline field analysis could significantly benefit the oil and natural gas industry.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"119 33","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139605377","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 paper intends for art of running heterogeneous-catalytic chemical reactions with high efficiency using column catalytic reactor with fixed catalyst layer. Described are potential possibilities of this undervalued apparatus to satisfy conditions for selective running of first step in multistep irreversible or reversible reactions in liquid-gas/vapor flow. Minor changes of working regime and construction of the apparatus discussed with the aim to increase the indexes. The idea of these changes is to suppress side reaction steps using due space localization and segregation of reaction participants. As a result, the needed reagents only have possibility for good contact with catalyst and each other. These features may straightly relate to reactionrectification, but realizes much cheaper. The examples chosen for demonstration are Ipatieff’s alkylation of benzene with propylene on “solid acid” and so called “selective hydrogenation” of acetylenes and conjugated dienes.
{"title":"Optimization of Reaction Conducting Efficiency by using the Potential of Column Catalytic Reactor","authors":"Katsman E","doi":"10.23880/ppej-16000378","DOIUrl":"https://doi.org/10.23880/ppej-16000378","url":null,"abstract":"The paper intends for art of running heterogeneous-catalytic chemical reactions with high efficiency using column catalytic reactor with fixed catalyst layer. Described are potential possibilities of this undervalued apparatus to satisfy conditions for selective running of first step in multistep irreversible or reversible reactions in liquid-gas/vapor flow. Minor changes of working regime and construction of the apparatus discussed with the aim to increase the indexes. The idea of these changes is to suppress side reaction steps using due space localization and segregation of reaction participants. As a result, the needed reagents only have possibility for good contact with catalyst and each other. These features may straightly relate to reactionrectification, but realizes much cheaper. The examples chosen for demonstration are Ipatieff’s alkylation of benzene with propylene on “solid acid” and so called “selective hydrogenation” of acetylenes and conjugated dienes.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"2 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140498641","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}
Surfactant flooding plays a crucial role in advanced techniques for boosting oil recovery. There remains a significant volume of unrecovered oil in reservoirs, particularly in carbonate reservoirs. These reservoirs often face challenges with low primary and water-flood recovery due to inadequate sweep efficiency, resulting in the presence of bypassed or trapped oil. Chemical flooding approaches, including surfactant flooding, have demonstrated their effectiveness in the retrieval of this trapped oil. The fundamental concept of surfactant flooding involves injecting a surface-active agent, known as a surfactant, to reduce the interfacial tension and mobilize the residual oil saturation. Surfactants have been widely utilized for various purposes in the petroleum industry since its early years, owing to their capacity to modify interfacial interactions between two immiscible fluids in contact with one another. Interfacial phenomena play a significant role in rock-fluid interactions and the interactions between fluids from the reservoir to distribution pipelines. Consequently, surfactants find application in a variety of activities within the petroleum industry. Laboratory experiments, pilot-scale projects, and field-scale initiatives worldwide have yielded diverse outcomes regarding the use of surfactants for enhancing oil recovery. Multiple types of surfactants have been investigated to determine highly effective chemical formulations for enhanced oil recovery, with anionic and non-ionic surfactants being commonly employed in sandstone reservoirs.
{"title":"Increasing Oil Recovery by Varying Surfactant Concentrations and Expanding the Well Drainage Area","authors":"Gurbanov E","doi":"10.23880/ppej-16000375","DOIUrl":"https://doi.org/10.23880/ppej-16000375","url":null,"abstract":"Surfactant flooding plays a crucial role in advanced techniques for boosting oil recovery. There remains a significant volume of unrecovered oil in reservoirs, particularly in carbonate reservoirs. These reservoirs often face challenges with low primary and water-flood recovery due to inadequate sweep efficiency, resulting in the presence of bypassed or trapped oil. Chemical flooding approaches, including surfactant flooding, have demonstrated their effectiveness in the retrieval of this trapped oil. The fundamental concept of surfactant flooding involves injecting a surface-active agent, known as a surfactant, to reduce the interfacial tension and mobilize the residual oil saturation. Surfactants have been widely utilized for various purposes in the petroleum industry since its early years, owing to their capacity to modify interfacial interactions between two immiscible fluids in contact with one another. Interfacial phenomena play a significant role in rock-fluid interactions and the interactions between fluids from the reservoir to distribution pipelines. Consequently, surfactants find application in a variety of activities within the petroleum industry. Laboratory experiments, pilot-scale projects, and field-scale initiatives worldwide have yielded diverse outcomes regarding the use of surfactants for enhancing oil recovery. Multiple types of surfactants have been investigated to determine highly effective chemical formulations for enhanced oil recovery, with anionic and non-ionic surfactants being commonly employed in sandstone reservoirs.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"1 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140499147","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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