Shale characterization is essential for understanding its potential as a hydrocarbon reservoir and for optimizing hydraulic fracturing operations. In this study, we evaluate the effectiveness of three methods for shale characterization: X-ray diffraction (XRD), cation exchange capacity (CEC), and linear swell meter (LSM). The study was conducted on a set of shale samples from a specific location. The samples were analyzed using XRD to determine their mineralogy, CEC to measure their ion exchange capacity, and LSM to assess their swelling properties. The results indicate that Clay stabilizers and KCl salt together perform much better. The concentrations of different additives can have a positive/negative effect on swelling. CEC values can be determined for each formation with the statistical method determined by using XRD results. Overall, the study highlights the potential of using a combination of XRD, CEC, and LSM for comprehensive shale characterization.
{"title":"Shale Characterization Methods Using XRD, CEC, and LSM: Experimental Findings","authors":"Alagoz E","doi":"10.23880/ppej-16000380","DOIUrl":"https://doi.org/10.23880/ppej-16000380","url":null,"abstract":"Shale characterization is essential for understanding its potential as a hydrocarbon reservoir and for optimizing hydraulic fracturing operations. In this study, we evaluate the effectiveness of three methods for shale characterization: X-ray diffraction (XRD), cation exchange capacity (CEC), and linear swell meter (LSM). The study was conducted on a set of shale samples from a specific location. The samples were analyzed using XRD to determine their mineralogy, CEC to measure their ion exchange capacity, and LSM to assess their swelling properties. The results indicate that Clay stabilizers and KCl salt together perform much better. The concentrations of different additives can have a positive/negative effect on swelling. CEC values can be determined for each formation with the statistical method determined by using XRD results. Overall, the study highlights the potential of using a combination of XRD, CEC, and LSM for comprehensive shale characterization.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"76 9-10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140499188","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}
Water-alternating-gas is commonly used in most of the existing enhanced oil recovery (EOR) projects in the world to regulate gas mobility and reduce fingering problems. Unfortunately, the expected recovery factor from most of the fields could not be attained with such EOR method. Development strategies of mature oil fields during the energy transition period may therefore involve the combination of polymer and CO2 injections to achieve incremental oil recovery and at the same time provide longterm geological storage solution for carbon. This paper therefore presents overview of the processes of polymer and CO2 floodings, and then highlights the overall benefits to be derived from the combination of CO2 and polymer flooding techniques in depleted hydrocarbon reservoirs, especially oil reservoirs. Reviews on studies related to the combinational CO2 and polymer injections are then carried out. Highlights of areas of the combinational CO2 and polymer injections needing more attention are also mentioned.
{"title":"Combinational CO2 and Polymer Injections for EOR and CO2 Storage in Depleted Reservoirs: A Mini Review on Laboratory, Simulation and Field Studies","authors":"Livinus A","doi":"10.23880/ppej-16000382","DOIUrl":"https://doi.org/10.23880/ppej-16000382","url":null,"abstract":"Water-alternating-gas is commonly used in most of the existing enhanced oil recovery (EOR) projects in the world to regulate gas mobility and reduce fingering problems. Unfortunately, the expected recovery factor from most of the fields could not be attained with such EOR method. Development strategies of mature oil fields during the energy transition period may therefore involve the combination of polymer and CO2 injections to achieve incremental oil recovery and at the same time provide longterm geological storage solution for carbon. This paper therefore presents overview of the processes of polymer and CO2 floodings, and then highlights the overall benefits to be derived from the combination of CO2 and polymer flooding techniques in depleted hydrocarbon reservoirs, especially oil reservoirs. Reviews on studies related to the combinational CO2 and polymer injections are then carried out. Highlights of areas of the combinational CO2 and polymer injections needing more attention are also mentioned.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"143 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140497983","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 designing pipeline facilities for production and transportation of oil, hydrocarbon gases or non-hydrocarbon gases – CO2 and H2 , consideration is given to pipeline integrity, flow assurance, operation and health/safety issues. Erosion-corrosion of the inner pipeline wall and/or high-pressure losses is of great concern. For many years now, many oil and gas field operators have adopted the America Petroleum Institute recommended practice 14E (API RP 14E) equation to estimate the erosional velocity. Unfortunately, the C-factor (which is an empirical constant) in the API RP 14E equation has been generalized to all field conditions. In addition, there is no concrete scientific evidence behind the basis of its formulation, and various values have been adopted based on field and laboratory experiences. In this work, we present how oil and gas companies could formulate safer erosional velocity models for their sand free or ‘clean service’ pipelines, based on the velocities calculated for the equilibrium flow rate (that is, the intersection of vertical lift performance (VLP) and inflow performance relationship (IPR)). The developed erosional velocity models can be applied, and compared with in-house correlations, for erosional velocity predictions
在设计用于生产和运输石油、碳氢化合物气体或非碳氢化合物气体（二氧化碳和 H2）的管道设施时，需要考虑管道的完整性、流量保证、运行和健康/安全问题。管道内壁的腐蚀和/或高压损失是一个非常值得关注的问题。多年来，许多油气田运营商都采用美国石油学会推荐实践 14E （API RP 14E）方程来估算侵蚀速度。遗憾的是，API RP 14E 公式中的 C 因子（这是一个经验常数）已被普遍应用于所有油田条件。此外，其计算公式背后并没有具体的科学依据，人们根据现场和实验室经验采用了不同的数值。在这项工作中，我们介绍了油气公司如何根据平衡流速（即垂直提升性能（VLP）和流入性能关系（IPR）的交叉点）计算出的速度，为其无砂或 "清洁服务 "管道制定更安全的侵蚀速度模型。开发的侵蚀速度模型可用于侵蚀速度预测，并与内部相关数据进行比较
{"title":"How Oil and Gas Companies can derive C-Factors in the API RP 14E Erosional Velocity Models for their ‘Clean Service’ Pipelines","authors":"Livinus A","doi":"10.23880/ppej-16000364","DOIUrl":"https://doi.org/10.23880/ppej-16000364","url":null,"abstract":"In designing pipeline facilities for production and transportation of oil, hydrocarbon gases or non-hydrocarbon gases – CO2 and H2 , consideration is given to pipeline integrity, flow assurance, operation and health/safety issues. Erosion-corrosion of the inner pipeline wall and/or high-pressure losses is of great concern. For many years now, many oil and gas field operators have adopted the America Petroleum Institute recommended practice 14E (API RP 14E) equation to estimate the erosional velocity. Unfortunately, the C-factor (which is an empirical constant) in the API RP 14E equation has been generalized to all field conditions. In addition, there is no concrete scientific evidence behind the basis of its formulation, and various values have been adopted based on field and laboratory experiences. In this work, we present how oil and gas companies could formulate safer erosional velocity models for their sand free or ‘clean service’ pipelines, based on the velocities calculated for the equilibrium flow rate (that is, the intersection of vertical lift performance (VLP) and inflow performance relationship (IPR)). The developed erosional velocity models can be applied, and compared with in-house correlations, for erosional velocity predictions","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139323238","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 research provides a comprehensive prediction using machine learning to predict vapor-liquid-equilibrium for CO2 - contained binary mixtures for carbon capture and sequestration projects. One of the best practices to lower the CO2 emissions in the atmosphere is Carbon Capture and Sequestration including capturing carbon dioxide from atmosphere and injecting it into the underground geological formations. One of the key elements in a successful project is to accurately model the phase equilibria which provides us on how the fluid or mixtures of the injected fluids will behave in certain pressures and temperatures underground. In this regard, different machine learning models have been implemented for the prediction. The data set consists experimental results of five different binary mixtures with CO2 presents in all of them. Then the results were compared to each other and the one with the highest accuracy was selected for each mixture. Peng Robinson equation of state was also used and compared with machine learning results. Finally, both machine learning and thermodynamic models were compared to experimental results to determine the accuracy. It was found out that thermodynamic model was unable to predict results for many data points while machine learning could predict results for most of the data points. Also, the accuracy of machine learning models was greatly better than thermodynamic model. In this research, a large data set including 748 data points is used on which machine learning models can be trained more accurate. Also, as a single machine learning model cannot predict accurate results for all mixtures, several models have been run on each mixture, and the one with the highest accuracy was selected for each CO2 -contained binary mixture which to our knowledge, has been never implemented.
{"title":"Prediction of Vapor Liquid Equilibrium of Binary CO2-Contained Mixtures for Carbon Capture and Sequestration using Artificial Intelligence","authors":"Rostami S","doi":"10.23880/ppej-16000365","DOIUrl":"https://doi.org/10.23880/ppej-16000365","url":null,"abstract":"This research provides a comprehensive prediction using machine learning to predict vapor-liquid-equilibrium for CO2 - contained binary mixtures for carbon capture and sequestration projects. One of the best practices to lower the CO2 emissions in the atmosphere is Carbon Capture and Sequestration including capturing carbon dioxide from atmosphere and injecting it into the underground geological formations. One of the key elements in a successful project is to accurately model the phase equilibria which provides us on how the fluid or mixtures of the injected fluids will behave in certain pressures and temperatures underground. In this regard, different machine learning models have been implemented for the prediction. The data set consists experimental results of five different binary mixtures with CO2 presents in all of them. Then the results were compared to each other and the one with the highest accuracy was selected for each mixture. Peng Robinson equation of state was also used and compared with machine learning results. Finally, both machine learning and thermodynamic models were compared to experimental results to determine the accuracy. It was found out that thermodynamic model was unable to predict results for many data points while machine learning could predict results for most of the data points. Also, the accuracy of machine learning models was greatly better than thermodynamic model. In this research, a large data set including 748 data points is used on which machine learning models can be trained more accurate. Also, as a single machine learning model cannot predict accurate results for all mixtures, several models have been run on each mixture, and the one with the highest accuracy was selected for each CO2 -contained binary mixture which to our knowledge, has been never implemented.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139323337","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}
Hydraulic jet fracturing, which integrates hydraulic sand jet perforation and hydraulic fracturing, is widely used in the stimulation of low permeability reservoir. However, due to the complexity of the fluid-solid interaction, the effect of pressurization characteristics and proppants transport in the perforation hole are still unclear. Therefore, in this paper, the pressurization characteristics and proppants transport of pulse jet fracturing are investigated under different pressure amplitude, angular velocity, average pressure, nozzle diameter and perforation diameter with the CFD-DEM (Computational Fluid Dynamics and Discrete Element Method) coupled method. Results indicates that the effect of pressure amplitude, average pressure are positively related to the maximum velocity and maximum total pressure, while the effect of nozzle diameter is positively correlated with the maximum velocity, and the maximum total pressure has a relatively small effect. The effect of perforation diameter is negatively related to maximum velocity. It can be seen that pulsed jet fracturing can effectively relieve the large number of proppants blocking present around the perforated inlet of a single section of the pulse jet fracturing model (SPJFM). But when the proppants are of a certain size and the nozzle diameter is very small, it is difficult for the proppants to enter the perforation. And the smaller the diameter of the perforation, the less proppant enters the perforation, and some of the proppant appears in the annular section. By reasonably designing the optimal parameters, the pulsed jet can maximize the pressurization, helping optimize jet fracturing application parameters.
{"title":"Pressurization Characteristics and Proppants Transport of Pulse Jet Fracturing with CFD-DEM Coupling Method","authors":"Cai C","doi":"10.23880/ppej-16000366","DOIUrl":"https://doi.org/10.23880/ppej-16000366","url":null,"abstract":"Hydraulic jet fracturing, which integrates hydraulic sand jet perforation and hydraulic fracturing, is widely used in the stimulation of low permeability reservoir. However, due to the complexity of the fluid-solid interaction, the effect of pressurization characteristics and proppants transport in the perforation hole are still unclear. Therefore, in this paper, the pressurization characteristics and proppants transport of pulse jet fracturing are investigated under different pressure amplitude, angular velocity, average pressure, nozzle diameter and perforation diameter with the CFD-DEM (Computational Fluid Dynamics and Discrete Element Method) coupled method. Results indicates that the effect of pressure amplitude, average pressure are positively related to the maximum velocity and maximum total pressure, while the effect of nozzle diameter is positively correlated with the maximum velocity, and the maximum total pressure has a relatively small effect. The effect of perforation diameter is negatively related to maximum velocity. It can be seen that pulsed jet fracturing can effectively relieve the large number of proppants blocking present around the perforated inlet of a single section of the pulse jet fracturing model (SPJFM). But when the proppants are of a certain size and the nozzle diameter is very small, it is difficult for the proppants to enter the perforation. And the smaller the diameter of the perforation, the less proppant enters the perforation, and some of the proppant appears in the annular section. By reasonably designing the optimal parameters, the pulsed jet can maximize the pressurization, helping optimize jet fracturing application parameters.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139323277","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}
{"title":"An Approach to Assess the Impact of Polyanionic Cellulose (PACLV) Polymer and Nanoparticles on Rheology and Filtration Control of Water-Based Muds","authors":"Adeyemi Ga","doi":"10.23880/ppej-16000363","DOIUrl":"https://doi.org/10.23880/ppej-16000363","url":null,"abstract":"","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"44 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139323012","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}
Sustainability goals integration in a petro-context could be considered irreconcilable. Harnessing SD goal synergies in the African petroleum sector may even be supremely problematic. Africa still grapples with a knotty mix of convoluted challenges, ranging from poverty, insecurity, drought, to extreme underdevelopment. Having contributed the least to the global climate dilemma, Africa still must bear the brunt of negative climate impacts, whilst shouldering its daunting chunk of climate adaptation and mitigation commitments. Moreover, a huge dependency on fuel imports, escalating debt profile and funding shortfalls, plague many countries at the subregional levels. In a relentless chronicle of woes, the region exhibits the highest energy deficiencies whilst contending with excruciatingly prohibitive petroleum importation costs soaring over $100 Billion USD annually. Similarly, Africa’s annual investment projections for energy are an estimated $190 billion USD. The implication is that, whereas the region has to achieve SD target obligations, its most credible means of optimising goal synergies, should be via an approach that targets energy sustainability, which remains an indispensable driver of most sustainability goals. To achieve this aim, a continental prioritization of regional partnerships is advocated to engender a sustainable petroleum sector. This is deemed crucial because of the considerable benefits the sector wields towards SDGs actualization and its relevance as a viable connector and pivot towards cleaner energy transition.
{"title":"Targeting Goal Synergies and Transnational Partnerships for Petro-Energy Sustainability in Africa","authors":"Ejenavi Ol","doi":"10.23880/ppej-16000362","DOIUrl":"https://doi.org/10.23880/ppej-16000362","url":null,"abstract":"Sustainability goals integration in a petro-context could be considered irreconcilable. Harnessing SD goal synergies in the African petroleum sector may even be supremely problematic. Africa still grapples with a knotty mix of convoluted challenges, ranging from poverty, insecurity, drought, to extreme underdevelopment. Having contributed the least to the global climate dilemma, Africa still must bear the brunt of negative climate impacts, whilst shouldering its daunting chunk of climate adaptation and mitigation commitments. Moreover, a huge dependency on fuel imports, escalating debt profile and funding shortfalls, plague many countries at the subregional levels. In a relentless chronicle of woes, the region exhibits the highest energy deficiencies whilst contending with excruciatingly prohibitive petroleum importation costs soaring over $100 Billion USD annually. Similarly, Africa’s annual investment projections for energy are an estimated $190 billion USD. The implication is that, whereas the region has to achieve SD target obligations, its most credible means of optimising goal synergies, should be via an approach that targets energy sustainability, which remains an indispensable driver of most sustainability goals. To achieve this aim, a continental prioritization of regional partnerships is advocated to engender a sustainable petroleum sector. This is deemed crucial because of the considerable benefits the sector wields towards SDGs actualization and its relevance as a viable connector and pivot towards cleaner energy transition.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139322940","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 compares the salt concentration and mineral composition of water from the Bakken Formation and the Inyan Kara Formation to assess their suitability for salt/critical minerals extraction. The results reveal that the Bakken Formation exhibits significantly higher levels of dissolved solids, calcium, magnesium, and chloride compared to the Inyan Kara Formation, indicating its potential suitability for salt/critical elements extraction. Conversely, the Inyan Kara Formation water displays higher bicarbonate concentrations, which may limit its applicability in certain salt extraction processes. The Bakken Formation proves more viable for water production due to its existing oil and gas infrastructure and abundant produced water from active and abandoned oil wells. This availability of produced water wells reduces the cost of critical mineral extraction and presents opportunities for water reuse or critical minerals sale, generating additional revenue that could offset recycling and disposal costs. In contrast, the absence of water production wells in the Inyan Kara Formation hinders its economic feasibility for salt/mineral extraction. The Inyan Kara Formation has a higher volume of water, but its lower salt content limits its usefulness for some purposes, especially in the energy industry for recovering rare earth minerals. Considering the higher mineralization, the concentration of key ions, and the presence of water production infrastructure, the Bakken Formation emerges as a more favorable choice for critical mineral extraction. However, factors like environmental impact and extraction costs should be considered in determining the most suitable formation. Despite data limitations, the study utilizes a valuable database to identify regional variations in salt concentrations for critical mineral extraction.
{"title":"Comparative Evaluation of the Feasibility of Utilizing the Bakken Formation Oil and Gas Field Produced Water for Extraction of Critical Minerals and Salts, with a Focus on the Inyan Kara Formation: An Analysis of Salinity and Infrastructure","authors":"Jakaria Md","doi":"10.23880/ppej-16000367","DOIUrl":"https://doi.org/10.23880/ppej-16000367","url":null,"abstract":"This study compares the salt concentration and mineral composition of water from the Bakken Formation and the Inyan Kara Formation to assess their suitability for salt/critical minerals extraction. The results reveal that the Bakken Formation exhibits significantly higher levels of dissolved solids, calcium, magnesium, and chloride compared to the Inyan Kara Formation, indicating its potential suitability for salt/critical elements extraction. Conversely, the Inyan Kara Formation water displays higher bicarbonate concentrations, which may limit its applicability in certain salt extraction processes. The Bakken Formation proves more viable for water production due to its existing oil and gas infrastructure and abundant produced water from active and abandoned oil wells. This availability of produced water wells reduces the cost of critical mineral extraction and presents opportunities for water reuse or critical minerals sale, generating additional revenue that could offset recycling and disposal costs. In contrast, the absence of water production wells in the Inyan Kara Formation hinders its economic feasibility for salt/mineral extraction. The Inyan Kara Formation has a higher volume of water, but its lower salt content limits its usefulness for some purposes, especially in the energy industry for recovering rare earth minerals. Considering the higher mineralization, the concentration of key ions, and the presence of water production infrastructure, the Bakken Formation emerges as a more favorable choice for critical mineral extraction. However, factors like environmental impact and extraction costs should be considered in determining the most suitable formation. Despite data limitations, the study utilizes a valuable database to identify regional variations in salt concentrations for critical mineral extraction.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139323276","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}
One of the key factors that analysts consider when calculating the economics of oil field development is the amount of oil in place (OIP). Conventional methods used for its estimation have some features affecting their predictive capabilities and applications. In addition, Oil bidders have limited time to evaluate and rank reservoirs from complex and large reservoir data packages - which sometimes fees are paid for their access. In this study, data-driven machine learning models - artificial neural network (ANN), support vector regression (SVR) and multiple linear regression (MLR) were developed for quick estimation of OIP for oil rim reservoirs in the Niger Delta. The models were evaluated using statistical error tools, and the results showed reasonable predictions. The sensitivity analysis performed on the selected input parameters showed that areal extent has the greatest impact on the estimation of the OIP with 29.94 %, oil formation volume factor has 22.74 % impact, oil column thickness was 16.61 %, m-factor has 13.29 %, water saturation was 9.01 %, and lastly porosity has 8.38 %. Comparison with recovery factor surrogate models existing in open literature were also carried out. The newly developed models can be helpful for oil bidders in ranking and evaluation of oil rim reservoirs in the Niger Delta.
{"title":"Predictive Models for Oil in Place for Oil Rim Reservoirs in the Niger Delta Using Machine Learning Approach","authors":"Livinus A","doi":"10.23880/ppej-16000361","DOIUrl":"https://doi.org/10.23880/ppej-16000361","url":null,"abstract":"One of the key factors that analysts consider when calculating the economics of oil field development is the amount of oil in place (OIP). Conventional methods used for its estimation have some features affecting their predictive capabilities and applications. In addition, Oil bidders have limited time to evaluate and rank reservoirs from complex and large reservoir data packages - which sometimes fees are paid for their access. In this study, data-driven machine learning models - artificial neural network (ANN), support vector regression (SVR) and multiple linear regression (MLR) were developed for quick estimation of OIP for oil rim reservoirs in the Niger Delta. The models were evaluated using statistical error tools, and the results showed reasonable predictions. The sensitivity analysis performed on the selected input parameters showed that areal extent has the greatest impact on the estimation of the OIP with 29.94 %, oil formation volume factor has 22.74 % impact, oil column thickness was 16.61 %, m-factor has 13.29 %, water saturation was 9.01 %, and lastly porosity has 8.38 %. Comparison with recovery factor surrogate models existing in open literature were also carried out. The newly developed models can be helpful for oil bidders in ranking and evaluation of oil rim reservoirs in the Niger Delta.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-07-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139357424","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}
Reliable gas hydrate equilibrium data is necessary to assess the severity of hydrate problems in the oil and gas industry and successfully implement the benefit of hydrate technologies in different areas such as hydrate-based CO2 capture and storage. Furthermore, the hydrate equilibrium point prediction models rely on tuning experimental data. In this mini-review, various techniques for hydrate dissociation point (DP) measurement either in the presence or absence of liquid water phase are discussed to improve the accuracy of the measurement. While both Visual and non-visual techniques can be used to measure hydrate DP, the non-visual isochore procedure is the most common technique. The stepwise heating procedure for hydrate dissociation to measure the DP is recommended due to its ability to improve accuracy and save time. However, it is essential to exercise caution during the data interpretation to avoid measuring inaccurate DP. In particular, considering the dissociation of various hydrate structures is crucial to enhance the accuracy of DP determination when employing non-visual techniques.
{"title":"Improving the Accuracy of Experimental Hydrate Equilibrium Point Determination: A Mini-Review","authors":"Aminnaji M","doi":"10.23880/ppej-16000355","DOIUrl":"https://doi.org/10.23880/ppej-16000355","url":null,"abstract":"Reliable gas hydrate equilibrium data is necessary to assess the severity of hydrate problems in the oil and gas industry and successfully implement the benefit of hydrate technologies in different areas such as hydrate-based CO2 capture and storage. Furthermore, the hydrate equilibrium point prediction models rely on tuning experimental data. In this mini-review, various techniques for hydrate dissociation point (DP) measurement either in the presence or absence of liquid water phase are discussed to improve the accuracy of the measurement. While both Visual and non-visual techniques can be used to measure hydrate DP, the non-visual isochore procedure is the most common technique. The stepwise heating procedure for hydrate dissociation to measure the DP is recommended due to its ability to improve accuracy and save time. However, it is essential to exercise caution during the data interpretation to avoid measuring inaccurate DP. In particular, considering the dissociation of various hydrate structures is crucial to enhance the accuracy of DP determination when employing non-visual techniques.","PeriodicalId":282073,"journal":{"name":"Petroleum & Petrochemical Engineering Journal","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-07-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124048553","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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