Soroush Kachoyan, Shaikh Nihaal, J. Oseh, Mohd Noorul Anam, A. Gbadamosi, A. Agi, R. Junin
The unstable wellbore created by the infiltration of drilling fluids into the reservoir formation is a great challenge in drilling operations. Reducing the fluid infiltration using nanoparticles (NPs) brings about a significant improvement in drilling operation. Herein, a mixture of iron oxide nanoparticle (IONP) and polyanionic cellulose nanoparticle (nano-PAC) additives were added to water-based mud (WBM) to determine their impact on rheological and filtration properties measured at 80 °F, 100 °F, and 250 °F. Polyanionic cellulose (PAC-R) was processed into nano-PAC by wet ball-milling process. The rheological behaviour, low-pressure low-temperature (LPLT), and high-pressure high-temperature (HPHT) filtration properties performance of IONP, nano-PAC, and IONP and nano-PAC mixtures were compared in the WBM. The results showed that IONP, nano-PAC, and synergy effect of IONP and nano-PAC in WBM at temperatures of 80 °F and 250 °F improved the density, 10-s and 10-min gel strength (10-s Gs and 10-min GS), plastic viscosity (PV), and the yield point (YP), while the pH was constant at 9.0. The mixture of 1.5 wt.% IONP + 0.25g nano-PAC in the WBM unveiled the most promising and optimal properties. At LPLT, the mixture improved the YP by 11% and reduced the LPLT fluid loss volume (FL) by 32.4%. At HPHT, the mud density increased by 3%, 10-s GS by 56%, 10-min GS by 52%, and the YP by 33.3%, while the HPHT FL decreased by 21%. With 1.0 g concentration at 100 °F, the nano-PAC achieved the greatest reduction in the FL of the WBM by 63%, followed by PAC-R by 57% before IONP that showed 36% reduction. Overall, the impact of IONP and nano-PAC in the WBM is evident and while the IONP showed more improved PV, the nano-PAC is more desirable for fluid loss control when 1.0 g at 100 °F was used. The use of combined IONP and nano-PAC could be beneficial for mitigating fluid loss and averting wellbore problem.
{"title":"Enhanced Rheological and Filtration Properties of Water-Based Mud Using Iron Oxide and Polyanionic Cellulose Nanoparticles","authors":"Soroush Kachoyan, Shaikh Nihaal, J. Oseh, Mohd Noorul Anam, A. Gbadamosi, A. Agi, R. Junin","doi":"10.2118/211924-ms","DOIUrl":"https://doi.org/10.2118/211924-ms","url":null,"abstract":"\u0000 The unstable wellbore created by the infiltration of drilling fluids into the reservoir formation is a great challenge in drilling operations. Reducing the fluid infiltration using nanoparticles (NPs) brings about a significant improvement in drilling operation. Herein, a mixture of iron oxide nanoparticle (IONP) and polyanionic cellulose nanoparticle (nano-PAC) additives were added to water-based mud (WBM) to determine their impact on rheological and filtration properties measured at 80 °F, 100 °F, and 250 °F. Polyanionic cellulose (PAC-R) was processed into nano-PAC by wet ball-milling process. The rheological behaviour, low-pressure low-temperature (LPLT), and high-pressure high-temperature (HPHT) filtration properties performance of IONP, nano-PAC, and IONP and nano-PAC mixtures were compared in the WBM. The results showed that IONP, nano-PAC, and synergy effect of IONP and nano-PAC in WBM at temperatures of 80 °F and 250 °F improved the density, 10-s and 10-min gel strength (10-s Gs and 10-min GS), plastic viscosity (PV), and the yield point (YP), while the pH was constant at 9.0. The mixture of 1.5 wt.% IONP + 0.25g nano-PAC in the WBM unveiled the most promising and optimal properties. At LPLT, the mixture improved the YP by 11% and reduced the LPLT fluid loss volume (FL) by 32.4%. At HPHT, the mud density increased by 3%, 10-s GS by 56%, 10-min GS by 52%, and the YP by 33.3%, while the HPHT FL decreased by 21%. With 1.0 g concentration at 100 °F, the nano-PAC achieved the greatest reduction in the FL of the WBM by 63%, followed by PAC-R by 57% before IONP that showed 36% reduction. Overall, the impact of IONP and nano-PAC in the WBM is evident and while the IONP showed more improved PV, the nano-PAC is more desirable for fluid loss control when 1.0 g at 100 °F was used. The use of combined IONP and nano-PAC could be beneficial for mitigating fluid loss and averting wellbore problem.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"36 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":"131636565","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sand production is a pertinent issue in oil and gas well engineering and a major cause of concern for the production engineer. He can plan for it, or he can prepare for it, albeit he would rather have it nipped in the bud right from the well’s completion phase. Sand production is costly, reducing the lifetime and durability of pipelines and production facilities, inadvertently impacting the company’s balance sheet negatively and in some cases reducing the life and productivity of the well itself. This paper critically evaluates sand production in the Niger Delta, using the Ibigwe field operated by Waltersmith Petroman Oil Limited as a case study. It proffers optimal sand exclusion methods for wells in the Niger Delta by analysing various subsurface datasets and historical sand production from offset wells within the field. The subsurface datasets identified as relevant to this study include sonic transit time, depth of burial of zones of interest, particle size analysis, geomechanical data (specifically unconfined compressive stress logs), Rate of Penetration (ROP) and other data logs. Evaluating all relevant data to the subject is imperative as discovered during research; none of the datasets listed above can be analysed in isolation, rather interdependently. The selection of an optimal sand exclusion method consequently affects the deployment of an effective completion mechanism and as such, this endeavour should be carried out conscientiously.
{"title":"Selection of Optimal Sand Exclusion Methods for Wells in The Onshore Niger Delta: The Ibigwe Field Case Study","authors":"C. E. Chime, Ibinabo Greenson Kalio","doi":"10.2118/211983-ms","DOIUrl":"https://doi.org/10.2118/211983-ms","url":null,"abstract":"\u0000 Sand production is a pertinent issue in oil and gas well engineering and a major cause of concern for the production engineer. He can plan for it, or he can prepare for it, albeit he would rather have it nipped in the bud right from the well’s completion phase. Sand production is costly, reducing the lifetime and durability of pipelines and production facilities, inadvertently impacting the company’s balance sheet negatively and in some cases reducing the life and productivity of the well itself. This paper critically evaluates sand production in the Niger Delta, using the Ibigwe field operated by Waltersmith Petroman Oil Limited as a case study. It proffers optimal sand exclusion methods for wells in the Niger Delta by analysing various subsurface datasets and historical sand production from offset wells within the field. The subsurface datasets identified as relevant to this study include sonic transit time, depth of burial of zones of interest, particle size analysis, geomechanical data (specifically unconfined compressive stress logs), Rate of Penetration (ROP) and other data logs. Evaluating all relevant data to the subject is imperative as discovered during research; none of the datasets listed above can be analysed in isolation, rather interdependently. The selection of an optimal sand exclusion method consequently affects the deployment of an effective completion mechanism and as such, this endeavour should be carried out conscientiously.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"30 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":"130757111","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}
Over the years, multilateral well technology has been one of the most rapidly evolving and widely utilized production technologies for new and maturing reservoirs. Multilateral wells have the potential for reservoir productivity improvement. The characteristics used to evaluate multilateral well completion are connectivity, isolation, and accessibility. All these focus on the completion design of the main bore, lateral bores, and junctions that connect the lateral and main bores. Hence, one of the factors to consider in designing multilateral wells is the junction type, which depends on the required degree of mechanical integrity and pressure integrity at each lateral. Previous studies establish that the lateral junctions are a critical element of multilateral completions and can fail under formation stresses, temperature-induced forces, and differential pressures during production. Thus, the reliability of a multilateral completion design is the ability to construct and complete the multilateral junction successfully. The Technology Advancement of Multilaterals (TAML) has categorized the distinct types of multilateral junctions based on support and hydraulic integrity provided at the junction. The objectives of this paper are: (1) to provide a detailed discussion on each classification level and the conditions in which they are applicable, (2) to present a conceptually digitized application of a multilateral well on a stacked reservoir XXXX in a Niger Delta field using SEPAL software. To achieve the latter goal, after a preliminary and detailed casing design, we applied the SEPAL software to design and digitize the proposed multilateral well schematics for the stacked reservoir. From the analysis, a multilateral level 5 junction was selected to overcome specific problems (e.g., wellbore collapse) due to the unconsolidated sands of the reservoir in the field of interest.
{"title":"Computer-Aided Design for a Multilateral Well Completion in a Stacked Reservoir","authors":"F. A. Bamgboye, Promise O. Longe, B. Oriji","doi":"10.2118/211980-ms","DOIUrl":"https://doi.org/10.2118/211980-ms","url":null,"abstract":"\u0000 Over the years, multilateral well technology has been one of the most rapidly evolving and widely utilized production technologies for new and maturing reservoirs. Multilateral wells have the potential for reservoir productivity improvement. The characteristics used to evaluate multilateral well completion are connectivity, isolation, and accessibility. All these focus on the completion design of the main bore, lateral bores, and junctions that connect the lateral and main bores. Hence, one of the factors to consider in designing multilateral wells is the junction type, which depends on the required degree of mechanical integrity and pressure integrity at each lateral. Previous studies establish that the lateral junctions are a critical element of multilateral completions and can fail under formation stresses, temperature-induced forces, and differential pressures during production. Thus, the reliability of a multilateral completion design is the ability to construct and complete the multilateral junction successfully. The Technology Advancement of Multilaterals (TAML) has categorized the distinct types of multilateral junctions based on support and hydraulic integrity provided at the junction. The objectives of this paper are: (1) to provide a detailed discussion on each classification level and the conditions in which they are applicable, (2) to present a conceptually digitized application of a multilateral well on a stacked reservoir XXXX in a Niger Delta field using SEPAL software. To achieve the latter goal, after a preliminary and detailed casing design, we applied the SEPAL software to design and digitize the proposed multilateral well schematics for the stacked reservoir. From the analysis, a multilateral level 5 junction was selected to overcome specific problems (e.g., wellbore collapse) due to the unconsolidated sands of the reservoir in the field of interest.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"28 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":"117242949","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}
J. Ugoyah, J. Ajienka, V. U. Wachikwu-Elechi, S. S. Ikiensikimama
During oil and gas production, scaling is a flow assurance problem commonly experienced in most regions. For scale control to be effective and less expensive, accurate prediction of scaling immediately deposition commences is important. This paper provides a model for the prediction of Barium Sulphate (BaSO4) and Calcium Carbonate (CaCO3) oilfield scales built using machine learning. Thermodynamic and compositional properties including temperature, pressure, PH, CO2 mole fraction, Total Dissolved Solids (TDS), and ion compositions of water samples from wells where BaSO4 and CaCO3 scales were observed are analysed and used to train the machine learning model. The results of the modelling indicate that the Decision tree model that had an accuracy of 0.91 value using Area Under Curve (AUC) score, performed better in predicting scale precipitation in the wells than the other Decision tree models that had AUC scores of 0.88 and 0.87. The model can guide early prediction and control of scaling during oil and gas production operations.
在油气生产过程中，结垢是大多数地区普遍遇到的流动保障问题。为了有效地控制结垢，降低成本，在沉积开始时对结垢进行准确的预测是很重要的。本文利用机器学习技术建立了硫酸钡(BaSO4)和碳酸钙(CaCO3)油田规模预测模型。对观察到BaSO4和CaCO3尺度的井中水样的热力学和组成特性(包括温度、压力、PH、CO2摩尔分数、总溶解固体(TDS)和离子组成)进行分析，并用于训练机器学习模型。建模结果表明，采用曲线下面积(Area Under Curve, AUC)评分的决策树模型预测井内尺度降水的精度为0.91，优于AUC评分分别为0.88和0.87的决策树模型。该模型可以指导油气生产过程中结垢的早期预测和控制。
{"title":"Prediction of Scale Precipitation by Modelling its Thermodynamic Properties using Machine Learning Engineering","authors":"J. Ugoyah, J. Ajienka, V. U. Wachikwu-Elechi, S. S. Ikiensikimama","doi":"10.2118/212010-ms","DOIUrl":"https://doi.org/10.2118/212010-ms","url":null,"abstract":"\u0000 During oil and gas production, scaling is a flow assurance problem commonly experienced in most regions. For scale control to be effective and less expensive, accurate prediction of scaling immediately deposition commences is important. This paper provides a model for the prediction of Barium Sulphate (BaSO4) and Calcium Carbonate (CaCO3) oilfield scales built using machine learning. Thermodynamic and compositional properties including temperature, pressure, PH, CO2 mole fraction, Total Dissolved Solids (TDS), and ion compositions of water samples from wells where BaSO4 and CaCO3 scales were observed are analysed and used to train the machine learning model. The results of the modelling indicate that the Decision tree model that had an accuracy of 0.91 value using Area Under Curve (AUC) score, performed better in predicting scale precipitation in the wells than the other Decision tree models that had AUC scores of 0.88 and 0.87. The model can guide early prediction and control of scaling during oil and gas production operations.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"31 21","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114115070","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}
Petrochemical exploration in Nigeria poses a significant threat to the environment, health and livelihoods of local people. The inability to find a holistic solution to address amicably the issues associated with oil and gas exploration and production has resulted in an unending wave of tension, crises and countless legal battles between communities and oil operators. This development is further complicated by the lack of adequate capacity on the part of regulators in the sector. The situation has forced some oil operators to move their operations from land and shallow waters into the deep sea with the hope to reduce hostilities within operational facilities and conflict with local people. Despite efforts to have a better understanding among the stakeholders, particularly oil operators and local communities, environmental issues persist creating mistrust between parties. Developing a chemical database with a comprehensive contaminants profile in the petrochemical industry would improve the management of chemical spills and associated issues and bring some level of fairness to conflict resolution in the sector.
{"title":"Developing a Chemical Database for Resolving Enviromental Issues in the Petrochemical Industry in Nigeria","authors":"A. Ekperusi, Anthonia Ejiroghene Gbuvboro","doi":"10.2118/211948-ms","DOIUrl":"https://doi.org/10.2118/211948-ms","url":null,"abstract":"\u0000 Petrochemical exploration in Nigeria poses a significant threat to the environment, health and livelihoods of local people. The inability to find a holistic solution to address amicably the issues associated with oil and gas exploration and production has resulted in an unending wave of tension, crises and countless legal battles between communities and oil operators. This development is further complicated by the lack of adequate capacity on the part of regulators in the sector. The situation has forced some oil operators to move their operations from land and shallow waters into the deep sea with the hope to reduce hostilities within operational facilities and conflict with local people. Despite efforts to have a better understanding among the stakeholders, particularly oil operators and local communities, environmental issues persist creating mistrust between parties. Developing a chemical database with a comprehensive contaminants profile in the petrochemical industry would improve the management of chemical spills and associated issues and bring some level of fairness to conflict resolution in the sector.","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":"123063524","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this study, the hole cleaning qualities of mud samples formulated with tigernut derivatives – starch and fibre – as additives were determined by adding drill cuttings as impurities and evaluating the Carrying Capacity Index (CCI) as well as Transport Index (TI) of the muds. Results of the analysis conducted for the mud properties showed that all the different mud properties but the pH of the mud evaluated of mud samples B, C1, C2, and C3 were slightly higher (albeit within the recommended values) than those of the control (standard) mud sample A. Using the results obtained from mud properties analysis and drilling operations data for the evaluation of the hole cleaning qualities, the following new expressions for optimum cuttings lifting ability (β) and cuttings lifting coefficient (β1), which gives criteria for cutting lifting in a wellbore were developed: β1 = 0.11519 [(1 − Cf)]−1(dp)−2.014. The higher the value of β1 greater than one, the better the hole cleaning ability of the mud and the lower the mud flowrate needed to achieve better hole cleaning for a given cutting particle size.
{"title":"Cuttings Lifting Coefficient Model: A Criteria for Cuttings Lifting and Hole Cleaning Quality of Mud in Drilling Optimization","authors":"D. Jimmy, E. Wami, Michael Ifeanyi Ogba","doi":"10.2118/212004-ms","DOIUrl":"https://doi.org/10.2118/212004-ms","url":null,"abstract":"\u0000 In this study, the hole cleaning qualities of mud samples formulated with tigernut derivatives – starch and fibre – as additives were determined by adding drill cuttings as impurities and evaluating the Carrying Capacity Index (CCI) as well as Transport Index (TI) of the muds. Results of the analysis conducted for the mud properties showed that all the different mud properties but the pH of the mud evaluated of mud samples B, C1, C2, and C3 were slightly higher (albeit within the recommended values) than those of the control (standard) mud sample A. Using the results obtained from mud properties analysis and drilling operations data for the evaluation of the hole cleaning qualities, the following new expressions for optimum cuttings lifting ability (β) and cuttings lifting coefficient (β1), which gives criteria for cutting lifting in a wellbore were developed: β1 = 0.11519 [(1 − Cf)]−1(dp)−2.014. The higher the value of β1 greater than one, the better the hole cleaning ability of the mud and the lower the mud flowrate needed to achieve better hole cleaning for a given cutting particle size.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"35 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":"128298795","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}
B. Obong, P. Adegoke, Soba Osuji-Bells, D. Ogbonna, Hassan Salisu, Onyinyechi Ekerenduh, Segun Adomokhai
In many ageing fields, there is a constant need to optimize production performance of the wells to ensure that they continue to deliver value. As a field matures, with high water and sand cut production from the wells, water breakthrough from water flooding projects and other artificial pressure maintenance programs, the produced fluid water cut and gas-oil ratio will be changing. For such fields, the optimal use of existing surface facilities is critical to sustaining and increasing well rates leading to a corresponding reduction in production costs. In the Ikanto field, Gas Lift is the preferred artificial lift method, and has been so for over twenty years. However, with increased water production from the wells, the field separating train is faced with handling produced water in the separator train. Other challenges in the gas lift system including obsolete field metering equipments, meter calibration and maintenance challenges, etc, have impacted optimization opportunities from the gas lifted wells. The resulting consequence is the inability to fully determine optimal lift gas injection rates if the lift gas injection into the well is over or under-injected in line with advised lift gas rates from well performance models. An important input for gas lift optimization is the volumetric flow rate of injection gas. This data can help experienced Production engineers and field technicians determine if the lift gas injection into the well is optimal, thus providing directional guidance on what change(s) should be made to improve the well performance. In order to ensure that the asset value is enhanced, an integrated approach to maximizing production from the field was deployed ranging from the upgrade and automation of the existing gas lift infrastructure in the field vis-à-vis carrying out gas lift system optimisation, carrying out de-bottlenecking of parts of the production system, and the installation of real time surface monitoring systems. In this paper, the results of the optimization efforts in the Ikanto field are discussed. The analysis of the results has resulted in an upscale of total daily production from the field by over thirty percent (30%).
{"title":"An Integrated Approach To Production Optimization In Ageing Gas Lifted Fields- Ikanto Field Experience","authors":"B. Obong, P. Adegoke, Soba Osuji-Bells, D. Ogbonna, Hassan Salisu, Onyinyechi Ekerenduh, Segun Adomokhai","doi":"10.2118/211961-ms","DOIUrl":"https://doi.org/10.2118/211961-ms","url":null,"abstract":"\u0000 In many ageing fields, there is a constant need to optimize production performance of the wells to ensure that they continue to deliver value. As a field matures, with high water and sand cut production from the wells, water breakthrough from water flooding projects and other artificial pressure maintenance programs, the produced fluid water cut and gas-oil ratio will be changing. For such fields, the optimal use of existing surface facilities is critical to sustaining and increasing well rates leading to a corresponding reduction in production costs.\u0000 In the Ikanto field, Gas Lift is the preferred artificial lift method, and has been so for over twenty years. However, with increased water production from the wells, the field separating train is faced with handling produced water in the separator train. Other challenges in the gas lift system including obsolete field metering equipments, meter calibration and maintenance challenges, etc, have impacted optimization opportunities from the gas lifted wells. The resulting consequence is the inability to fully determine optimal lift gas injection rates if the lift gas injection into the well is over or under-injected in line with advised lift gas rates from well performance models. An important input for gas lift optimization is the volumetric flow rate of injection gas. This data can help experienced Production engineers and field technicians determine if the lift gas injection into the well is optimal, thus providing directional guidance on what change(s) should be made to improve the well performance.\u0000 In order to ensure that the asset value is enhanced, an integrated approach to maximizing production from the field was deployed ranging from the upgrade and automation of the existing gas lift infrastructure in the field vis-à-vis carrying out gas lift system optimisation, carrying out de-bottlenecking of parts of the production system, and the installation of real time surface monitoring systems.\u0000 In this paper, the results of the optimization efforts in the Ikanto field are discussed. The analysis of the results has resulted in an upscale of total daily production from the field by over thirty percent (30%).","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"44 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115672879","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper investigated the biodegradation of selected hydrocarbons (e.g., alkanes, such as decane, and others) by open mixed microbial cultures. Laboratory experiments were conducted with the aim to investigate the rate of biodegradation of dodecane using glass bioreactors over an incubation period of 31days. In the study, dodecane represented the hydrocarbon used, and the microbial activity was subjected to aerobic conditions. Mineral water was used to stimulate the microbial growth. The results obtained indicated that an increase in the rate of biodegradation can be achieved, thus resulting in an increase in the oil recovery efficiency. It can be inferred that MEOR is a "high-risk, high reward" process, depending on whether the microorganisms can produce oil recovery-enhancing chemicals by utilizing the residual oil within the reservoir as a carbon source. The high risk in this context refers to the severe constraints that the microbial system must satisfy in order to utilize an in-situ carbon source. The rewards however are that the logistical cost and difficulty in implementing the process is similar to those of implementing a waterflood.
{"title":"Microbial Enhanced Oil Recovery (MEOR): mechanism, rate of biodegradation of hydrocarbon, field applications and challenges","authors":"F. Okoro, Patricia Odukwe, Mary Frank-Okoro","doi":"10.2118/211939-ms","DOIUrl":"https://doi.org/10.2118/211939-ms","url":null,"abstract":"\u0000 This paper investigated the biodegradation of selected hydrocarbons (e.g., alkanes, such as decane, and others) by open mixed microbial cultures. Laboratory experiments were conducted with the aim to investigate the rate of biodegradation of dodecane using glass bioreactors over an incubation period of 31days. In the study, dodecane represented the hydrocarbon used, and the microbial activity was subjected to aerobic conditions. Mineral water was used to stimulate the microbial growth. The results obtained indicated that an increase in the rate of biodegradation can be achieved, thus resulting in an increase in the oil recovery efficiency. It can be inferred that MEOR is a \"high-risk, high reward\" process, depending on whether the microorganisms can produce oil recovery-enhancing chemicals by utilizing the residual oil within the reservoir as a carbon source. The high risk in this context refers to the severe constraints that the microbial system must satisfy in order to utilize an in-situ carbon source. The rewards however are that the logistical cost and difficulty in implementing the process is similar to those of implementing a waterflood.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"26 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":"127647318","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}
N. Okereke, I. Ogazi, A. Umofia, N. Ohia, S. Udeagbara, O. Nwanwe, Henry Adimekwe, S. Ekwueme, A. Kerunwa
Slugging studies done recently have shown that slug mitigation techniques need to be improved, particularly in deepwater scenarios. In order to breakup the liquid slugs inside the riser and reduce acute slugging, the gas-lift slug mitigation method involves injecting a pre-determined volume of gas at the pipeline-riser section. Through OLGA severe slug mitigation; the study investigated various positioning of the gas-lift upstream of the riser-base. A case-study of a typical deepwater scenario within West-Africa was considered. The field was located at a water-depth of over 1000m with riser height of 1513m and pipeline section of 2712m which were all modeled on OLGA. The study involved validation of the pressure simulated against initial pressure behavior from the field. The field case involved running well X1 set up at about 72°C and mass flow rate of 3.25 kg/s, well X2 set up at about 70°C and 12.13 kg/smultiphase flow stream flow. Gas-lift was deployed within range of 7kg/s to 35 kg/s. Although severe slugging was mitigated, the power consumption required by required by gas-lift technique proved to be relatively high. The results indicated that gas-lift was better off closer to the supporting wells than being at the riser-base; as with the scenario of 35 kg/s gas-lift closer to well X2, the gas pressure upstream of the riser-base was significant enough to push off liquid slugs that accumulated at the riser-base; giving rise to a more stable flow and moderating the severe slugging scenario.
{"title":"Investigation of Gas-Lift Mitigation in Deepwater Pipeline-Riser System","authors":"N. Okereke, I. Ogazi, A. Umofia, N. Ohia, S. Udeagbara, O. Nwanwe, Henry Adimekwe, S. Ekwueme, A. Kerunwa","doi":"10.2118/212008-ms","DOIUrl":"https://doi.org/10.2118/212008-ms","url":null,"abstract":"\u0000 Slugging studies done recently have shown that slug mitigation techniques need to be improved, particularly in deepwater scenarios. In order to breakup the liquid slugs inside the riser and reduce acute slugging, the gas-lift slug mitigation method involves injecting a pre-determined volume of gas at the pipeline-riser section. Through OLGA severe slug mitigation; the study investigated various positioning of the gas-lift upstream of the riser-base. A case-study of a typical deepwater scenario within West-Africa was considered. The field was located at a water-depth of over 1000m with riser height of 1513m and pipeline section of 2712m which were all modeled on OLGA. The study involved validation of the pressure simulated against initial pressure behavior from the field. The field case involved running well X1 set up at about 72°C and mass flow rate of 3.25 kg/s, well X2 set up at about 70°C and 12.13 kg/smultiphase flow stream flow. Gas-lift was deployed within range of 7kg/s to 35 kg/s. Although severe slugging was mitigated, the power consumption required by required by gas-lift technique proved to be relatively high.\u0000 The results indicated that gas-lift was better off closer to the supporting wells than being at the riser-base; as with the scenario of 35 kg/s gas-lift closer to well X2, the gas pressure upstream of the riser-base was significant enough to push off liquid slugs that accumulated at the riser-base; giving rise to a more stable flow and moderating the severe slugging scenario.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"71 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":"126711467","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The use of viscosity enhancer in Polymer flooding decreases mobility and improves sweep efficiency of flood water. However, there is a likelihood of permeability impairment due to the polymer retention onto the rock surface. This leads to formation damage. Therefore, a good assessment and evaluation of this problem is important to oil recovery sustenance. In this study, the permeability reduction caused by some local polymers in Nigeria used for Enhanced Oil Recovery was investigated. A laboratory study was carried out using unconsolidated core plugs (sands packs) and crude oil from the Niger Delta field. Two of the core plug samples (control samples) were flooded with simulated brine concentration and viscosity of 20000ppm and 0.949cP respectively. Cisus populnea (Okoho), Abelmoschus esculentus (Okro), Irvingia gabonensis (Ogbono) and Gum Arabic were used as polymers. Water breakthrough time, oil recovery and mobility ratio results obtained from fourteen samples were recorded and compared with that obtained from using only brine. The permeabilities of core plug samples were estimated prior to and after polymer flooding by pressure drop calculation. Residual Resistant Factor (RRF) and adsorption capacity of these polymers at same concentrations of 1000 ppm, 2500 ppm and 5000 ppm were also estimated. At 5000ppm, the RRF and mobility ratio for Cisus populnea, Abelmoschus esculentus, Gum Arabic and Irvingia gabonensis were 2.341/0.91., 1.354/0.35, 2567/0.56 and 3/0.66 respectively. The percentage reduction in permeability and displacement efficiency for Cisus populnea, Abelmoschus esculentus and Gum Arabic are 3.9%/75.30%, 2.7%/89.50% and 4.2%/77% respectively. It was observed that there was no-flow while flooding with Irvingia gabonensis at 5000ppm. The results from the study indicate that Irvingia gabonensis triggered the highest permeability impairment while Abelmoschus esculentus gave the least permeability impairment. The best performed polymer is Abelmoschus esculentus with highest displacement efficiency, reduced mobility ratio, lowest RRF values, lowest static and dynamic adsorption.
{"title":"Investigation of Permeability Impairment Using Local Polymers for Enhanced Oil Recovery","authors":"C. U. Uzoho, Enaanabhel Ade, M. Onyekonwu","doi":"10.2118/211922-ms","DOIUrl":"https://doi.org/10.2118/211922-ms","url":null,"abstract":"\u0000 The use of viscosity enhancer in Polymer flooding decreases mobility and improves sweep efficiency of flood water. However, there is a likelihood of permeability impairment due to the polymer retention onto the rock surface. This leads to formation damage. Therefore, a good assessment and evaluation of this problem is important to oil recovery sustenance. In this study, the permeability reduction caused by some local polymers in Nigeria used for Enhanced Oil Recovery was investigated. A laboratory study was carried out using unconsolidated core plugs (sands packs) and crude oil from the Niger Delta field. Two of the core plug samples (control samples) were flooded with simulated brine concentration and viscosity of 20000ppm and 0.949cP respectively. Cisus populnea (Okoho), Abelmoschus esculentus (Okro), Irvingia gabonensis (Ogbono) and Gum Arabic were used as polymers. Water breakthrough time, oil recovery and mobility ratio results obtained from fourteen samples were recorded and compared with that obtained from using only brine. The permeabilities of core plug samples were estimated prior to and after polymer flooding by pressure drop calculation. Residual Resistant Factor (RRF) and adsorption capacity of these polymers at same concentrations of 1000 ppm, 2500 ppm and 5000 ppm were also estimated. At 5000ppm, the RRF and mobility ratio for Cisus populnea, Abelmoschus esculentus, Gum Arabic and Irvingia gabonensis were 2.341/0.91., 1.354/0.35, 2567/0.56 and 3/0.66 respectively. The percentage reduction in permeability and displacement efficiency for Cisus populnea, Abelmoschus esculentus and Gum Arabic are 3.9%/75.30%, 2.7%/89.50% and 4.2%/77% respectively. It was observed that there was no-flow while flooding with Irvingia gabonensis at 5000ppm. The results from the study indicate that Irvingia gabonensis triggered the highest permeability impairment while Abelmoschus esculentus gave the least permeability impairment. The best performed polymer is Abelmoschus esculentus with highest displacement efficiency, reduced mobility ratio, lowest RRF values, lowest static and dynamic adsorption.","PeriodicalId":399294,"journal":{"name":"Day 2 Tue, August 02, 2022","volume":"116 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134097521","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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