Much research has been conducted to determine the impact of gas injection settings on residual natural gas recovery and CO2 sequestration. However, little research has been conducted on how reservoir pore pressure varies during natural gas displacement by CO2 flooding. Using a core flooding experiment, this article examined the effects of gas injections on reservoir pore pressure and compression ratio. A core flooding experiment was done at 30-40 °C and 1500 psig to investigate the effect of gas injections on reservoir pore pressure and compression ratio. The CO2 injection rate and N2 booster volume were adjusted to 0.2-1.2 ml/min and 8-36 cm3, respectively. Because of the turbulence effect, high mean interstitial velocity raises the molecular kinetic energy of the gas species, which subsequently influences the molecular agitation of the gas species and so alleviates reservoir pressure and gas compression. The typical CO2 injection experiments revealed substantial compression and pore pressure rises as the injection rate increased. The trial with N2 as a booster resulted in a steady increase, which explains their low dispersion coefficient value. As a result, there is less gas mixing and compression compared with typical CO2 flooding.
{"title":"Experimental Study on Gas Reservoir Pore Pressure Changes During Natural Gas Recovery and CO2 Storage in Porous Medium","authors":"N. Mohammed, Abubakar Abbas J., Godpower Enyi C.","doi":"10.2118/211971-ms","DOIUrl":"https://doi.org/10.2118/211971-ms","url":null,"abstract":"\u0000 Much research has been conducted to determine the impact of gas injection settings on residual natural gas recovery and CO2 sequestration. However, little research has been conducted on how reservoir pore pressure varies during natural gas displacement by CO2 flooding. Using a core flooding experiment, this article examined the effects of gas injections on reservoir pore pressure and compression ratio. A core flooding experiment was done at 30-40 °C and 1500 psig to investigate the effect of gas injections on reservoir pore pressure and compression ratio. The CO2 injection rate and N2 booster volume were adjusted to 0.2-1.2 ml/min and 8-36 cm3, respectively. Because of the turbulence effect, high mean interstitial velocity raises the molecular kinetic energy of the gas species, which subsequently influences the molecular agitation of the gas species and so alleviates reservoir pressure and gas compression. The typical CO2 injection experiments revealed substantial compression and pore pressure rises as the injection rate increased. The trial with N2 as a booster resulted in a steady increase, which explains their low dispersion coefficient value. As a result, there is less gas mixing and compression compared with typical CO2 flooding.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"1 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":"116635724","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}
T. Jenakumo, O. Adekoya, Joshua Itua, Abidemi Belgore, A. Nkanga, O. Olagunju, A. Bisain
The Bonga field is in its late stage Phase-3 development. Infill wells are drilled to target oil in the bypassed or unswept areas of the reservoirs. Unlike the earlier phases of development, the current wells have complex trajectories and are hooked up via crowded subsea manifolds. Because oflimited availability of drilling centers, most of the new wells are extended reach with narrow drilling margins. The target reservoirs are relatively thinner, poorly developed, and more limited in extent and size compared to targets in the earlier phases, increasing inherent subsurface uncertainties. With an expected low case ultimate recovery per well of roughly 10–15 MMstb, and average deepwater well cost of +/- $40 million, the stakes were high and hence critical to get it right the first time. If net-sand is poor or short because of suboptimal landing or well placement in the reservoir, the well objective (recovery and rate) can easily be compromised and could require drilling a sidetrack with additional attendant cost. Longer exposure length of drain hole (reservoir section) was known to improve well production rates hence an essential component of the well plan. To address these challenges and ensure the wells achieve their objectives and deliver their economic value, a geosteering technology (Reservoir Mapping While Drilling tool—GeoSphere) was adopted for optimal landing above the target reservoir(s) and placement within the reservoir channel sands using the Multilayer Distance to Boundary technology (PeriScopeHD). The deployment of geosteering technology was considered to be a success in enabling better sand exposures of the wells in the target sections, thus achieving the well objectives. This paper discusses the implementation of geosteering technology and learnings from two case studies in the Bonga infill campaign.
{"title":"Overcoming the Late-Stage Development Challenges of Bonga Turbidite Reservoirs via Geosteering Technology Deployment","authors":"T. Jenakumo, O. Adekoya, Joshua Itua, Abidemi Belgore, A. Nkanga, O. Olagunju, A. Bisain","doi":"10.2118/212029-ms","DOIUrl":"https://doi.org/10.2118/212029-ms","url":null,"abstract":"\u0000 The Bonga field is in its late stage Phase-3 development. Infill wells are drilled to target oil in the bypassed or unswept areas of the reservoirs. Unlike the earlier phases of development, the current wells have complex trajectories and are hooked up via crowded subsea manifolds. Because oflimited availability of drilling centers, most of the new wells are extended reach with narrow drilling margins.\u0000 The target reservoirs are relatively thinner, poorly developed, and more limited in extent and size compared to targets in the earlier phases, increasing inherent subsurface uncertainties. With an expected low case ultimate recovery per well of roughly 10–15 MMstb, and average deepwater well cost of +/- $40 million, the stakes were high and hence critical to get it right the first time. If net-sand is poor or short because of suboptimal landing or well placement in the reservoir, the well objective (recovery and rate) can easily be compromised and could require drilling a sidetrack with additional attendant cost. Longer exposure length of drain hole (reservoir section) was known to improve well production rates hence an essential component of the well plan.\u0000 To address these challenges and ensure the wells achieve their objectives and deliver their economic value, a geosteering technology (Reservoir Mapping While Drilling tool—GeoSphere) was adopted for optimal landing above the target reservoir(s) and placement within the reservoir channel sands using the Multilayer Distance to Boundary technology (PeriScopeHD). The deployment of geosteering technology was considered to be a success in enabling better sand exposures of the wells in the target sections, thus achieving the well objectives.\u0000 This paper discusses the implementation of geosteering technology and learnings from two case studies in the Bonga infill campaign.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"268 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":"120896765","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}
Lithology identification is an important aspect in reservoir characterization with one of its main purpose of well planning and drilling activities. A faster and more effective lithology identification could be obtained from an ensemble of optimized models using voting classifiers. In this study, a voting classifier machine learning model was developed to predict the lithology of different lithologies using an assembly of different classification algorithms: Support Vector Machine (SVM), Logistic Regression, Random Forest Classifier, K-Nearest Neighbor, and Multilayer Perceptron (MLP) models. The result of the comparative analysis shows that the implementation of the voting classifier model helped to increase the prediction performance by 1.50% compared to the individual models. Despite a small significance at deployment in real scenario it improves the chances of classifying the lithology.
{"title":"Hybridization of Optimized Supervised Machine Learning Algorithms for Effective Lithology","authors":"Ebenezer Aniyom, A. Chikwe, J. Odo","doi":"10.2118/212019-ms","DOIUrl":"https://doi.org/10.2118/212019-ms","url":null,"abstract":"\u0000 Lithology identification is an important aspect in reservoir characterization with one of its main purpose of well planning and drilling activities. A faster and more effective lithology identification could be obtained from an ensemble of optimized models using voting classifiers. In this study, a voting classifier machine learning model was developed to predict the lithology of different lithologies using an assembly of different classification algorithms: Support Vector Machine (SVM), Logistic Regression, Random Forest Classifier, K-Nearest Neighbor, and Multilayer Perceptron (MLP) models. The result of the comparative analysis shows that the implementation of the voting classifier model helped to increase the prediction performance by 1.50% compared to the individual models. Despite a small significance at deployment in real scenario it improves the chances of classifying the lithology.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"5 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":"125923039","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}
Joseph Emmanuel Akhagbeme, J. Ajienka, V. U. Wachikwu-Elechi, S. S. Ikiensikimama
The total dissolved solid (TDS) of formation water has an impact on its tendency to form or dissociate Gas Hydrate in gas production, handling and subsea transportation systems. The effect of salinity of formation water on hydrate formation and dissociation was studied in this paper. Two seawater samples (SW1 and SW2) of different salinities: 35.4g/L and 34.8g/L respectively, and synthetic seawater sample (SSW) were used. Afresh water sample was used for comparison. The SSW sample with a salinity of 36.0g/L experienced a longer onset time for hydrate to form, and dissociated quickly in this sample than the rest samples. The onset time for hydrate formation increased as formation water salt content increases and vice versa for dissociation. The 0.04 wt% concentration of the commercial kinetic hydrate inhibitor (PVCap) used, performed better for the hydrate inhibition experiment involving the SW1 by reducing pressure to 120 psi. This attained pressure at the end of the experiment was lesser than the values obtained with the rest concentrations. The 0.01 wt% concentration of PVCap reduced pressure to a lesser value when compared to the values obtained using other concentrations for the experiment conducted with SSW.
{"title":"Gas Hydrate Formation and Dissociation: Effect of Salinity of Formation Water in Subsea Flowline","authors":"Joseph Emmanuel Akhagbeme, J. Ajienka, V. U. Wachikwu-Elechi, S. S. Ikiensikimama","doi":"10.2118/212011-ms","DOIUrl":"https://doi.org/10.2118/212011-ms","url":null,"abstract":"\u0000 The total dissolved solid (TDS) of formation water has an impact on its tendency to form or dissociate Gas Hydrate in gas production, handling and subsea transportation systems. The effect of salinity of formation water on hydrate formation and dissociation was studied in this paper. Two seawater samples (SW1 and SW2) of different salinities: 35.4g/L and 34.8g/L respectively, and synthetic seawater sample (SSW) were used. Afresh water sample was used for comparison. The SSW sample with a salinity of 36.0g/L experienced a longer onset time for hydrate to form, and dissociated quickly in this sample than the rest samples. The onset time for hydrate formation increased as formation water salt content increases and vice versa for dissociation. The 0.04 wt% concentration of the commercial kinetic hydrate inhibitor (PVCap) used, performed better for the hydrate inhibition experiment involving the SW1 by reducing pressure to 120 psi. This attained pressure at the end of the experiment was lesser than the values obtained with the rest concentrations. The 0.01 wt% concentration of PVCap reduced pressure to a lesser value when compared to the values obtained using other concentrations for the experiment conducted with SSW.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"174 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":"122982619","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}
Geothermal resources are characterized by hard rocks with very high temperatures making it difficult to implement conventional tools for petrophysical analysis such as lithological identification. Several computation and artificial intelligence models such as K-means clustering algorithms have been applied, however, these algorithms are limited to certain applications due to the available data utilized and high computation time. It is hence pertinent to consider a robust model that can meet up with these requirements. In this study, a proposed hybrid machine learning probabilistic ranking system was developed which considered the integration of several pattern recognition algorithms in the identification of formation lithology. The ranking system leverages on the large volume of drilling and log data collected from conventional oil and gas operation to develop five embedded lithology identification models: K-means clustering, Hierarchical clustering using ward linkage, K-mode clustering, Birch, Mini-batch kmeans. The analysis was carried out using gamma ray logs, density logs, neutron porosity logs and Spontaneous potential as input parameters in building the lithology identification models while rate of penetration, surface RPM, Flow in, surface torque and pump pressure were utilized to predict the different lithologies using the different pattern recognition models as outputs. The output derived from the respective lithology identification models are further ranked based on a probabilistic approach to predict the actual lithology of the encountered formation. The results show that the implementation of the ranking system was effective in identifying the lithology of the drilled formation.
{"title":"Hybridized Probabilistic Machine Learning Ranking System for Lithological Identification in Geothermal Resources","authors":"P. Ekeopara, J. Odo, B. Obah, Valerian Nwankwo","doi":"10.2118/212015-ms","DOIUrl":"https://doi.org/10.2118/212015-ms","url":null,"abstract":"\u0000 Geothermal resources are characterized by hard rocks with very high temperatures making it difficult to implement conventional tools for petrophysical analysis such as lithological identification. Several computation and artificial intelligence models such as K-means clustering algorithms have been applied, however, these algorithms are limited to certain applications due to the available data utilized and high computation time. It is hence pertinent to consider a robust model that can meet up with these requirements.\u0000 In this study, a proposed hybrid machine learning probabilistic ranking system was developed which considered the integration of several pattern recognition algorithms in the identification of formation lithology. The ranking system leverages on the large volume of drilling and log data collected from conventional oil and gas operation to develop five embedded lithology identification models: K-means clustering, Hierarchical clustering using ward linkage, K-mode clustering, Birch, Mini-batch kmeans. The analysis was carried out using gamma ray logs, density logs, neutron porosity logs and Spontaneous potential as input parameters in building the lithology identification models while rate of penetration, surface RPM, Flow in, surface torque and pump pressure were utilized to predict the different lithologies using the different pattern recognition models as outputs. The output derived from the respective lithology identification models are further ranked based on a probabilistic approach to predict the actual lithology of the encountered formation. The results show that the implementation of the ranking system was effective in identifying the lithology of the drilled formation.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"47 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":"128522891","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}
As fields brown out, opportunities tend to shrink in size and recoverable volumes necessitating the design of innovative cost efficient re-development solutions to address increased surface and subsurface challenges. A prominent surface challenge with in-fill drilling on shallow offshore brown fields is slot availability, since the existing platform slots are typically in active use. Some of the known time and cost efficient means of addressing this issue, includes internal slot add-ons, deck extensions for external slot add-ons and shared wellhead systems – all of which can be accommodated up to the design limit of the existing platform. There is also the option of scaled-down platforms such as conductor supported platforms which present a cheaper alternative to conventional jacket platforms. This paper describes a structured approach applied on a brown field in Nigeria, to determine the re-use potential of existing wells on an offshore platform. The case study starts by identifying shut-in wells and active wells which have expected end of producing lives that precede the planned infill drilling period. These wells are then screened out and evaluated for further immediate to near-term utility such as rigless intervention, stimulation, recompletion and workover. The remaining wells form an inventory of the potential donor wells for sidetrack feasibility assessment, which takes into consideration wellbore architecture, casing sizes/depths, environmental regulatory requirements, P&A complexity, surface equipment constraints and well integrity aspects. The identification and categorization of potential donor wells provides the basis for the final step in the workflow which is trajectory feasibility study against identified subsurface targets. The overall objective is to reduce or eliminate the need for new platforms and consequently improve the economics of infill projects.
{"title":"Workflow for Slot Re-Utilization Assessment on Offshore Brown Fields to Improve Re-Development Profitability – A Case Study in Nigeria","authors":"Mirian Kosi Orji, Ademola Olatunbosun, Gbenga Abe, Uhunoma Osaigbovo, John Agiaye, Toyin Arowosafe","doi":"10.2118/211927-ms","DOIUrl":"https://doi.org/10.2118/211927-ms","url":null,"abstract":"\u0000 As fields brown out, opportunities tend to shrink in size and recoverable volumes necessitating the design of innovative cost efficient re-development solutions to address increased surface and subsurface challenges. A prominent surface challenge with in-fill drilling on shallow offshore brown fields is slot availability, since the existing platform slots are typically in active use. Some of the known time and cost efficient means of addressing this issue, includes internal slot add-ons, deck extensions for external slot add-ons and shared wellhead systems – all of which can be accommodated up to the design limit of the existing platform. There is also the option of scaled-down platforms such as conductor supported platforms which present a cheaper alternative to conventional jacket platforms.\u0000 This paper describes a structured approach applied on a brown field in Nigeria, to determine the re-use potential of existing wells on an offshore platform. The case study starts by identifying shut-in wells and active wells which have expected end of producing lives that precede the planned infill drilling period. These wells are then screened out and evaluated for further immediate to near-term utility such as rigless intervention, stimulation, recompletion and workover. The remaining wells form an inventory of the potential donor wells for sidetrack feasibility assessment, which takes into consideration wellbore architecture, casing sizes/depths, environmental regulatory requirements, P&A complexity, surface equipment constraints and well integrity aspects. The identification and categorization of potential donor wells provides the basis for the final step in the workflow which is trajectory feasibility study against identified subsurface targets.\u0000 The overall objective is to reduce or eliminate the need for new platforms and consequently improve the economics of infill projects.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"144 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":"123467906","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}
Enhanced oil recovery (EOR) is important to the petroleum industry mostly because it is used to improve oil recovery. Miscible gas flooding, a type of EOR process that is proven and economically viable can significantly increase oil recovery from reservoirs. In this study, the minimum miscibility pressure (MMP) in gas floods for different gases were computed using empirical correlations (Glaso correlation for hydrocarbon gas injection, Emera, Yuan et al and Glaso correlation for pure carbon dioxide gas injection, Sebastin and Yuan correlation for impure carbon dioxide correlations and Glaso, Firoozabadi and Aziz correlations for nitrogen gas injection). An efficient computer program was developed using visual basic programing language. Employing its highly versatile features, friendly graphical user interface (GUI) forms were designed and robust codes were developed. Validation was done for the program and results showed that the software which was developed had acceptable level of accuracy, was fast and effective. The study provides a new and cost effective way of checking for MMP which will enhance the process of screening gas flooding processes for the reservoir.
{"title":"Algorithm to Compute the Minimum Miscibility Pressure (MMP) for Gases in Gas Flooding Process","authors":"Elohor Diamond Akpobi, Efeosa Praise Oboh","doi":"10.2118/211973-ms","DOIUrl":"https://doi.org/10.2118/211973-ms","url":null,"abstract":"\u0000 Enhanced oil recovery (EOR) is important to the petroleum industry mostly because it is used to improve oil recovery. Miscible gas flooding, a type of EOR process that is proven and economically viable can significantly increase oil recovery from reservoirs. In this study, the minimum miscibility pressure (MMP) in gas floods for different gases were computed using empirical correlations (Glaso correlation for hydrocarbon gas injection, Emera, Yuan et al and Glaso correlation for pure carbon dioxide gas injection, Sebastin and Yuan correlation for impure carbon dioxide correlations and Glaso, Firoozabadi and Aziz correlations for nitrogen gas injection). An efficient computer program was developed using visual basic programing language. Employing its highly versatile features, friendly graphical user interface (GUI) forms were designed and robust codes were developed. Validation was done for the program and results showed that the software which was developed had acceptable level of accuracy, was fast and effective. The study provides a new and cost effective way of checking for MMP which will enhance the process of screening gas flooding processes for the reservoir.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"301 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":"116163785","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}
Pressure buildup test analysis has been used to investigate near wellbore environment, estimate reservoir pressure and reveal external reservoir boundary types. However, despite of these benefits no consideration has been given for the angle of inclination of the faults or boundaries within which the well is completed. The angle of inclination of the boundaries of a reservoir has a significant impact on the pressure behavior and performance of a well. Knowledge of the inclination angle of the faults assist in well placement for optimum production. The objective of this paper, therefore, is to develop a procedure for calculating the angle of a well completed within a pair of inclined sealing faults using pressure buildup test analysis. A well completed in an infinite-acting reservoir produces number of images inversely proportional to the angle of inclination and dependent on nature of the faults. This number of images, n, can also be related to the angle at which the faults are inclined. The principle of superposition is used to aggregate pressure drop history of a vertical shutin after a constant rate of production. Pressure buildup test procedure was developed from the total pressure expression following the rate history. The procedure considered fault angle and distances from an object well of every image formed because of the inclination of the sealing faults. The buildup test procedure developed shows linear partial variation of Horner ratio at early shutin time and late shutin time, assuming constant rate of production before shut in. The coefficient of the early time Horner's ratio is the early flow time slope. The late time Horner's ratio has coefficient which is the product of the early time slope and the number of images formed due to sealing faults angle. The result shows that that the model is only valid for long shutin time, and the second slope must be gotten at the late time region for higher accuracy. Finally, the procedure does not depend on well design or distances of the images from the object well. The analysis procedure developed here can be used to estimate the angle of inclination of two faults within which a well is completed. Near wellbore characterization is also possible. Decision on well location for optimum well production or injection can be made from the angle of inclination of the faults.
{"title":"Pressure Buildup Test Analysis Procedure of a Vertical Well Completed Within a Pair of Inclined Sealing Faults","authors":"Paul Olabi, S. Adewole","doi":"10.2118/211907-ms","DOIUrl":"https://doi.org/10.2118/211907-ms","url":null,"abstract":"\u0000 Pressure buildup test analysis has been used to investigate near wellbore environment, estimate reservoir pressure and reveal external reservoir boundary types. However, despite of these benefits no consideration has been given for the angle of inclination of the faults or boundaries within which the well is completed. The angle of inclination of the boundaries of a reservoir has a significant impact on the pressure behavior and performance of a well. Knowledge of the inclination angle of the faults assist in well placement for optimum production.\u0000 The objective of this paper, therefore, is to develop a procedure for calculating the angle of a well completed within a pair of inclined sealing faults using pressure buildup test analysis.\u0000 A well completed in an infinite-acting reservoir produces number of images inversely proportional to the angle of inclination and dependent on nature of the faults. This number of images, n, can also be related to the angle at which the faults are inclined. The principle of superposition is used to aggregate pressure drop history of a vertical shutin after a constant rate of production. Pressure buildup test procedure was developed from the total pressure expression following the rate history.\u0000 The procedure considered fault angle and distances from an object well of every image formed because of the inclination of the sealing faults.\u0000 The buildup test procedure developed shows linear partial variation of Horner ratio at early shutin time and late shutin time, assuming constant rate of production before shut in. The coefficient of the early time Horner's ratio is the early flow time slope. The late time Horner's ratio has coefficient which is the product of the early time slope and the number of images formed due to sealing faults angle.\u0000 The result shows that that the model is only valid for long shutin time, and the second slope must be gotten at the late time region for higher accuracy. Finally, the procedure does not depend on well design or distances of the images from the object well.\u0000 The analysis procedure developed here can be used to estimate the angle of inclination of two faults within which a well is completed. Near wellbore characterization is also possible. Decision on well location for optimum well production or injection can be made from the angle of inclination of the faults.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"18 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":"128177881","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}
Opeyemi Oluwalade, Y. Adeeyo, Frank Emeruwa, Nnamdi Nwabulue, Adaora Obi-Okoye, Adekanmi Adesola
The ability to have data and manipulate it to uncover meaningful information is a must-have skill in this day and age. In this paper, practical techniques were applied to combine and analyze 65 sets of well test data received from the Field Engineers for a particular well (Well-001). Comparisons were made between manually collating (copy and paste) and analyzing the data and applying Data Science techniques. Analysis was also done after collation of this data. It was on the basis of this review that it was observed that the well had a corroded bean box and that was replaced, while further analysis on the other hand showed that in the future, a Water Shut Off (WSO) and perforation extension opportunity could be carried out to boost and optimize production in this particular well. The emphasis of this paper is not on the analysis of the data but comparing various tools that can be used to combine large data from different excel files and collating them into one sheet for analysis and pointing out how man-hours can be optimized by applying Data Science. Data used in this paper were routine Field reports stored in a file that pertains to a Well in one of the Fields of interest. One of the takeaways from the job done here is that we can achieve more in less time from Data Science tools and codes like R, Python, VBA and also other tools like Power Query and Pivot Tables.
{"title":"Collation, Analysis of Oil and Gas Production Reports Using Excel, Python and R: A Data Science Approach in Handling Large Data","authors":"Opeyemi Oluwalade, Y. Adeeyo, Frank Emeruwa, Nnamdi Nwabulue, Adaora Obi-Okoye, Adekanmi Adesola","doi":"10.2118/212031-ms","DOIUrl":"https://doi.org/10.2118/212031-ms","url":null,"abstract":"\u0000 The ability to have data and manipulate it to uncover meaningful information is a must-have skill in this day and age. In this paper, practical techniques were applied to combine and analyze 65 sets of well test data received from the Field Engineers for a particular well (Well-001). Comparisons were made between manually collating (copy and paste) and analyzing the data and applying Data Science techniques. Analysis was also done after collation of this data.\u0000 It was on the basis of this review that it was observed that the well had a corroded bean box and that was replaced, while further analysis on the other hand showed that in the future, a Water Shut Off (WSO) and perforation extension opportunity could be carried out to boost and optimize production in this particular well.\u0000 The emphasis of this paper is not on the analysis of the data but comparing various tools that can be used to combine large data from different excel files and collating them into one sheet for analysis and pointing out how man-hours can be optimized by applying Data Science. Data used in this paper were routine Field reports stored in a file that pertains to a Well in one of the Fields of interest. One of the takeaways from the job done here is that we can achieve more in less time from Data Science tools and codes like R, Python, VBA and also other tools like Power Query and Pivot Tables.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"127 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":"131352481","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}
Underground storage of carbon dioxide (CO2) has been recognized as a viable strategy to reduce CO2 emissions in the atmosphere. In this context, numerical reservoir simulations are routinely implemented to predict the performance of the project under different operational scenarios and uncertainties. However, numerical simulators are intensive in terms of cost, computational time, and data requirement, thus limiting its use for early commercial applications especially for feasibility studies or quick evaluations. This paper presents the application of a simplified modelling approach to predict dimensionless pressure build-up and injectivity index based on an analytical model for reservoirs in Niger Delta. Data from four (4) Niger Delta reservoirs such as relative permeabilities, reservoir pressure, brine viscosity, and injection rate, among others were used in this work. A modified version of the physics-based model of Mishra et. al was used for conducting the studies. Therefore, equations governing the dimensionless pressure build-up and injectivity index were used to investigate the reservoir and operational characteristics of the well injection of CO2 in Niger delta reservoirs as an alternative to full-field numerical simulation. The model approximates the CO2 injection rate for a given target pressure differential or alternatively, the pressure differential that would result from injecting CO2 at a target rate, given the initial permeability, porosity, permeability, and injection rate. The results were used to rank the reservoirs based on suitability to CO2 sequestration, the displacement efficiency of the CO2 and potential storage in the reservoir. This approach is the first one carried out in the Niger Delta and provides the chance to assess the performance of CO2 storage capacity as a strategy to combat global warming from Nigeria.
{"title":"Evaluating Injectivity Index of Niger Delta Reservoirs for CO2 Geological Sequestration","authors":"Ifeoluwa Jayeola, B. Olusola","doi":"10.2118/211986-ms","DOIUrl":"https://doi.org/10.2118/211986-ms","url":null,"abstract":"\u0000 Underground storage of carbon dioxide (CO2) has been recognized as a viable strategy to reduce CO2 emissions in the atmosphere. In this context, numerical reservoir simulations are routinely implemented to predict the performance of the project under different operational scenarios and uncertainties. However, numerical simulators are intensive in terms of cost, computational time, and data requirement, thus limiting its use for early commercial applications especially for feasibility studies or quick evaluations. This paper presents the application of a simplified modelling approach to predict dimensionless pressure build-up and injectivity index based on an analytical model for reservoirs in Niger Delta. Data from four (4) Niger Delta reservoirs such as relative permeabilities, reservoir pressure, brine viscosity, and injection rate, among others were used in this work. A modified version of the physics-based model of Mishra et. al was used for conducting the studies. Therefore, equations governing the dimensionless pressure build-up and injectivity index were used to investigate the reservoir and operational characteristics of the well injection of CO2 in Niger delta reservoirs as an alternative to full-field numerical simulation. The model approximates the CO2 injection rate for a given target pressure differential or alternatively, the pressure differential that would result from injecting CO2 at a target rate, given the initial permeability, porosity, permeability, and injection rate. The results were used to rank the reservoirs based on suitability to CO2 sequestration, the displacement efficiency of the CO2 and potential storage in the reservoir. This approach is the first one carried out in the Niger Delta and provides the chance to assess the performance of CO2 storage capacity as a strategy to combat global warming from Nigeria.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"209 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":"126135902","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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