Delivering a data science project encompasses several hurdles that need to be addressed. As the project matures, the business requirements may change over time. In addition, uncertainties associated with data integrity, quantity, and quality can have an impact on the success of the project. The effectiveness of advanced analytics and algorithms that is changing depending on the complexity of the project and ambiguities in project values potentially will lead to adverse effects on deliverables and task prioritization. Agile-scrum framework enables projects with time-boxed iterations (sprints). It also introduces delivery through increments (MVPs) that assist in reaching the overall aim or vision of the product. However, backlog prioritization and sequence of tasks is not bounded by any criteria and depends fully on product owner’s understanding of product goal and value. On the other hand, CRISP-DM is a solid place to start for advising developers on the steps and tasks needed to build a data science product. It enables exploratory and discovery work through iterations to satisfy the requirements of the data science project. However, the lack of time element within the process might cause infinite iterative cycles and delay delivery to customers. At Petronas, we have integrated a hybrid strategy that envelops the CRISP-DM process within defined time-limited sprints. The process flow from CRISP-DM can help to plan which tasks to be assigned in which sprint. Properly assigned scrum team roles will ensure proper establishment of scrum. Furthermore, conducting scrum events will enable effective and productive customers engagement. Periodic inspection of scrum artifacts will also ensure alignment with product goals. This hybrid approach demonstrates how the change in requirements can be strategically addressed by utilizing the Agile-Scrum CRISP-DM methodology while ensuring that the product goal is achieved. It also highlights how Agile-Scrum ensures successful delivery of product, maximizing product value, and customer satisfaction, while CRISP-DM can guide us in planning for data science project sprints.
{"title":"Synergizing Hybrid Agile-Scrum and CRISP-DM Approaches in Data Science Project Management","authors":"E. Amirian, A. Abdollahzadeh, N. Sulaiman","doi":"10.2118/218114-ms","DOIUrl":"https://doi.org/10.2118/218114-ms","url":null,"abstract":"\u0000 Delivering a data science project encompasses several hurdles that need to be addressed. As the project matures, the business requirements may change over time. In addition, uncertainties associated with data integrity, quantity, and quality can have an impact on the success of the project. The effectiveness of advanced analytics and algorithms that is changing depending on the complexity of the project and ambiguities in project values potentially will lead to adverse effects on deliverables and task prioritization.\u0000 Agile-scrum framework enables projects with time-boxed iterations (sprints). It also introduces delivery through increments (MVPs) that assist in reaching the overall aim or vision of the product. However, backlog prioritization and sequence of tasks is not bounded by any criteria and depends fully on product owner’s understanding of product goal and value. On the other hand, CRISP-DM is a solid place to start for advising developers on the steps and tasks needed to build a data science product. It enables exploratory and discovery work through iterations to satisfy the requirements of the data science project. However, the lack of time element within the process might cause infinite iterative cycles and delay delivery to customers.\u0000 At Petronas, we have integrated a hybrid strategy that envelops the CRISP-DM process within defined time-limited sprints. The process flow from CRISP-DM can help to plan which tasks to be assigned in which sprint. Properly assigned scrum team roles will ensure proper establishment of scrum. Furthermore, conducting scrum events will enable effective and productive customers engagement. Periodic inspection of scrum artifacts will also ensure alignment with product goals.\u0000 This hybrid approach demonstrates how the change in requirements can be strategically addressed by utilizing the Agile-Scrum CRISP-DM methodology while ensuring that the product goal is achieved. It also highlights how Agile-Scrum ensures successful delivery of product, maximizing product value, and customer satisfaction, while CRISP-DM can guide us in planning for data science project sprints.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"270 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284957","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 oil and gas industry approaches field development in many ways. One approach is to drill and produce unstimulated open-hole horizontal multilateral (also referred to as multileg) wells. The Clearwater formation, among others in the Western Canadian Sedimentary Basin (WCSB) is an excellent example of this strategy. A method to positively determine flow contribution from each leg has been historically lacking. An innovative approach, using existing tracer technology is now available to provide these insights. As drilling is completed for each lateral leg, a unique oil soluble tracer, chemically bonded to a resin (sand-like) solid carrier is displaced out the drilling string while pulling out of hole. This tracer is normally spotted in the toe region to provide toe flow monitoring; Occasionally, a second unique tracer is spotted halfway through the same leg for mid leg flow monitoring. Volumetric calculations estimate required volumes for displacement. This process is repeated with unique tracers for each displacement. Hydrocarbon samples collected at surface upon initial production are analyzed for the presence of these tracers to assess contribution from each traced section. Over the last three (3) years, oil tracers have been utilized in approximately two hundred (200) multilateral wells to monitor hydrocarbon contribution of each drilled/traced leg. On average these wells have six (6) legs but can range from two (2) to more than ten (>10). Approximately one thousand two hundred (1,200) individual lateral legs have been traced and monitored. Oil sample analyses results have provided indication of which legs contribute initial flow, or present partial or total leg integrity concerns. While sampling schedules are typically designed for three (3) months of monitoring, oil soluble tracers are detectable in produced hydrocarbon for periods ranging from weeks to months, depending mainly on production rates. Tracer concentrations provide a relative productivity assessment of each leg over time. Overall, the deployment of oil tracers with a solid carrying mechanism in unstimulated open hole multilateral wells has provided operators with an efficient strategy to verify hydrocarbon contribution from each individual leg. Future work to increase value of this diagnostic application aims to integrate tracer characteristic performance of each multilateral well with its production, drilling, and subsurface datasets, to identify patterns and correlations between datasets to assist operators in their development plans. Additionally, future work aims to extend the tracer detection window to allow for monitoring multilateral wells that present elevated borehole collapse risk beyond the initial months of flow.
{"title":"Chemical Tracing Diagnostic Application for Monitoring Flow Contribution in Unstimulated Open Hole Multi-Lateral Wells Utilizing An Engineered Solid Carrier","authors":"C. Mombourquette, A. Martinez","doi":"10.2118/218057-ms","DOIUrl":"https://doi.org/10.2118/218057-ms","url":null,"abstract":"\u0000 The oil and gas industry approaches field development in many ways. One approach is to drill and produce unstimulated open-hole horizontal multilateral (also referred to as multileg) wells. The Clearwater formation, among others in the Western Canadian Sedimentary Basin (WCSB) is an excellent example of this strategy. A method to positively determine flow contribution from each leg has been historically lacking. An innovative approach, using existing tracer technology is now available to provide these insights.\u0000 As drilling is completed for each lateral leg, a unique oil soluble tracer, chemically bonded to a resin (sand-like) solid carrier is displaced out the drilling string while pulling out of hole. This tracer is normally spotted in the toe region to provide toe flow monitoring; Occasionally, a second unique tracer is spotted halfway through the same leg for mid leg flow monitoring. Volumetric calculations estimate required volumes for displacement. This process is repeated with unique tracers for each displacement. Hydrocarbon samples collected at surface upon initial production are analyzed for the presence of these tracers to assess contribution from each traced section.\u0000 Over the last three (3) years, oil tracers have been utilized in approximately two hundred (200) multilateral wells to monitor hydrocarbon contribution of each drilled/traced leg. On average these wells have six (6) legs but can range from two (2) to more than ten (>10). Approximately one thousand two hundred (1,200) individual lateral legs have been traced and monitored. Oil sample analyses results have provided indication of which legs contribute initial flow, or present partial or total leg integrity concerns.\u0000 While sampling schedules are typically designed for three (3) months of monitoring, oil soluble tracers are detectable in produced hydrocarbon for periods ranging from weeks to months, depending mainly on production rates. Tracer concentrations provide a relative productivity assessment of each leg over time. Overall, the deployment of oil tracers with a solid carrying mechanism in unstimulated open hole multilateral wells has provided operators with an efficient strategy to verify hydrocarbon contribution from each individual leg.\u0000 Future work to increase value of this diagnostic application aims to integrate tracer characteristic performance of each multilateral well with its production, drilling, and subsurface datasets, to identify patterns and correlations between datasets to assist operators in their development plans. Additionally, future work aims to extend the tracer detection window to allow for monitoring multilateral wells that present elevated borehole collapse risk beyond the initial months of flow.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"6 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395798","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}
Jorge Yanez, Roberto Fuenmayor, Prasoon Srivastava, Nael Sadek, Pedro Vivas
During times of uncertainty, upstream producers focus on cost optimization and maximizing net profit bound by the highest safety and environmental impact. They seek the ability to decrease system failure rates, consequently minimizing downtime and lifting costs by extending equipment running life and optimizing operating costs. This paper's main objective is to showcase field results for electric submersible pump (ESP) optimization, ranking, and automatic event detection. The Oriente Basin is the largest brownfield in Ecuador, from approximately 100 producer wells. Production is achieved from different reservoirs with a high water cut. The artificial lift method selected for these wells is solely ESP. There are several operational challenges; however, the main challenge is to rank the wells that need attention to act upon, to successfully improve the efficiency of operations to maximize productivity and reduce the ESP failure event. A smart digital system was installed and equipped with trained artificial intelligence and machine learning (AI/ML) to predict a catalog of undesired and critical events and suggest potential actions, to reduce the time of action and avoid production losses and improve the ESPs’ performance indexes; specifically, mean time before failure (MTBF) and failure index (FI). To achieve these goals, it is necessary to create a digital ecosystem that enables the integration of tools, surveillance, and knowledge. This integration must coincide with the process of going through a digital transformation. The framework includes gathering ESP data frequently, creating a fingerprint for the key ESP problems, understanding how operations conditions vary, and automatically updating the threshold. Opportunities are identified by implementing well thresholds, severity ranking systems, and AI/ML with advanced detection of undesired operating conditions. Integrating the digital solution, in addition to continuous well review and diagnostics by specialist staff, detected critical ESP events, generated key alarms, and provided communication with the field in the appropriate time and way. Together these resulted in enhancing the ESP run life from 247 days to almost fourfold which is 950 days (about 2 and a half years). The capacity to combine field knowledge and real-time data enabled with a rapid response AI/ML customized catalog of workflows created the possibility of intelligent actions in the digital field operations by detecting and ranking operational events, creating a focused list of potential failure threats and providing insights of required actions to change course. In conclusion, it reduced the number of ESPs to be shut in every year.
{"title":"Applying Digital Rapid Response Ranking and Event Detection System in Oriente Basin","authors":"Jorge Yanez, Roberto Fuenmayor, Prasoon Srivastava, Nael Sadek, Pedro Vivas","doi":"10.2118/218125-ms","DOIUrl":"https://doi.org/10.2118/218125-ms","url":null,"abstract":"\u0000 During times of uncertainty, upstream producers focus on cost optimization and maximizing net profit bound by the highest safety and environmental impact. They seek the ability to decrease system failure rates, consequently minimizing downtime and lifting costs by extending equipment running life and optimizing operating costs. This paper's main objective is to showcase field results for electric submersible pump (ESP) optimization, ranking, and automatic event detection.\u0000 The Oriente Basin is the largest brownfield in Ecuador, from approximately 100 producer wells. Production is achieved from different reservoirs with a high water cut. The artificial lift method selected for these wells is solely ESP. There are several operational challenges; however, the main challenge is to rank the wells that need attention to act upon, to successfully improve the efficiency of operations to maximize productivity and reduce the ESP failure event.\u0000 A smart digital system was installed and equipped with trained artificial intelligence and machine learning (AI/ML) to predict a catalog of undesired and critical events and suggest potential actions, to reduce the time of action and avoid production losses and improve the ESPs’ performance indexes; specifically, mean time before failure (MTBF) and failure index (FI).\u0000 To achieve these goals, it is necessary to create a digital ecosystem that enables the integration of tools, surveillance, and knowledge. This integration must coincide with the process of going through a digital transformation. The framework includes gathering ESP data frequently, creating a fingerprint for the key ESP problems, understanding how operations conditions vary, and automatically updating the threshold. Opportunities are identified by implementing well thresholds, severity ranking systems, and AI/ML with advanced detection of undesired operating conditions.\u0000 Integrating the digital solution, in addition to continuous well review and diagnostics by specialist staff, detected critical ESP events, generated key alarms, and provided communication with the field in the appropriate time and way. Together these resulted in enhancing the ESP run life from 247 days to almost fourfold which is 950 days (about 2 and a half years).\u0000 The capacity to combine field knowledge and real-time data enabled with a rapid response AI/ML customized catalog of workflows created the possibility of intelligent actions in the digital field operations by detecting and ranking operational events, creating a focused list of potential failure threats and providing insights of required actions to change course. In conclusion, it reduced the number of ESPs to be shut in every year.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"51 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394695","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}
H. Amer, K. Sheng, R. Okuno, A. Filstein, M. French, J. Sanchez, A. Al-Gawfi, P. Nakutnyy
Dimethyl ether (DME) as a water-soluble solvent has been studied as a potential additive to steam for improving the energy efficiency of steam-assisted gravity drainage (SAGD). The main objective of this research was to study in-situ flow characteristics and energy efficiency of DME-SAGD using a large-scale physical model. Results from DME-SAGD were compared with the control experiment of SAGD with no solvent injection using the same experimental setup. The main novelty of this research lies in the experimental data that demonstrated enhanced bitumen drainage by DME-SAGD in comparison to SAGD. The experiment was conducted in a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.22 m, which contained a sand pack with a porosity of 0.34 and a permeability of 5.0 D. The DME-SAGD experiment used a DME concentration of 10 mol% and a steam co-injection rate of 27.6 cm3/min [cold-water equivalent (CWE)] at 3000 kPa. Temperature distributions within the sand pack, along with injection and production histories, were recorded during the experiment. Subsequently, numerical simulations were performed to history-match the experimental data, and the calibrated simulation model was used to analyze details of compositional flow characteristics. Results showed that the 10 mol% DME-SAGD experiment yielded a recovery factor of 92.7% in 4.2 days, and the SAGD experiment yielded a recovery factor of 68.6% in 6.0 days, for both of which the first 2 days were the preheating and the steam-only injection (SAGD) stages. The peak rate of bitumen production was 43.8 mL/min in the DME-SAGD experiment, which was more than twice greater than the peak rates observed in the SAGD experiment. The substantially increased rate of bitumen production resulted in a cumulative steam-to-oil ratio in DME-SAGD that was less than half of that in SAGD. Analysis of experimental results indicated that the solubility of DME in the aqueous and oleic phases caused different flow characteristics between DME-SAGD and SAGD. For example, the oleic and aqueous phases were more uniformly distributed in the sand pack in the former. Simulations indicated that DME-SAGD had a uniform distribution of greater grid-scale Bond numbers and increased oleic-phase mobilities in comparison to SAGD.
{"title":"A Study of DME-Steam Co-Injection Using a Large-Scale Physical Model","authors":"H. Amer, K. Sheng, R. Okuno, A. Filstein, M. French, J. Sanchez, A. Al-Gawfi, P. Nakutnyy","doi":"10.2118/218077-ms","DOIUrl":"https://doi.org/10.2118/218077-ms","url":null,"abstract":"\u0000 Dimethyl ether (DME) as a water-soluble solvent has been studied as a potential additive to steam for improving the energy efficiency of steam-assisted gravity drainage (SAGD). The main objective of this research was to study in-situ flow characteristics and energy efficiency of DME-SAGD using a large-scale physical model. Results from DME-SAGD were compared with the control experiment of SAGD with no solvent injection using the same experimental setup. The main novelty of this research lies in the experimental data that demonstrated enhanced bitumen drainage by DME-SAGD in comparison to SAGD.\u0000 The experiment was conducted in a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.22 m, which contained a sand pack with a porosity of 0.34 and a permeability of 5.0 D. The DME-SAGD experiment used a DME concentration of 10 mol% and a steam co-injection rate of 27.6 cm3/min [cold-water equivalent (CWE)] at 3000 kPa. Temperature distributions within the sand pack, along with injection and production histories, were recorded during the experiment. Subsequently, numerical simulations were performed to history-match the experimental data, and the calibrated simulation model was used to analyze details of compositional flow characteristics.\u0000 Results showed that the 10 mol% DME-SAGD experiment yielded a recovery factor of 92.7% in 4.2 days, and the SAGD experiment yielded a recovery factor of 68.6% in 6.0 days, for both of which the first 2 days were the preheating and the steam-only injection (SAGD) stages. The peak rate of bitumen production was 43.8 mL/min in the DME-SAGD experiment, which was more than twice greater than the peak rates observed in the SAGD experiment. The substantially increased rate of bitumen production resulted in a cumulative steam-to-oil ratio in DME-SAGD that was less than half of that in SAGD.\u0000 Analysis of experimental results indicated that the solubility of DME in the aqueous and oleic phases caused different flow characteristics between DME-SAGD and SAGD. For example, the oleic and aqueous phases were more uniformly distributed in the sand pack in the former. Simulations indicated that DME-SAGD had a uniform distribution of greater grid-scale Bond numbers and increased oleic-phase mobilities in comparison to SAGD.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395353","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}
Yishu Li, Zhongwei Du, Bo Wang, Jiasheng Ding, Fanhua Zeng
Foamy oil flow is a pivotal aspect of the cyclic solvent injection (CSI) process, yet the influence of water and foam stabilizers, such as nanoparticles, on its efficacy remains insufficiently elucidated. Consequently, a profound comprehension of how waterflooding and nanoparticles impact CSI performance is imperative for advancing oil recovery strategies. This study conducted a meticulously designed experimental investigation to investigate the roles of water and nanoparticles in a CO2-based CSI process. Three distinct tests were executed utilizing a cylindrical sandpack at varying injection pressures. Test 1 entailed a standard CO2-based CSI process for baseline comparison. Test 2 involved a waterflooding process with an injection volume of 1.5 PV, succeeded by a CO2-based CSI process. Test 3 featured a hybrid process comprising the sequence: CSI-waterflooding-CSI-Nanoparticle solution flooding-CSI. Key parameters including injection rate, injection volume, sandpack pressure, production rate, cumulative production, and water cut were meticulously monitored and recorded. Thorough data analytics were then employed to scrutinize the impact of water and nanoparticles, identifying mechanisms for enhancing the CSI process. Laboratory results revealed that the total oil recovery in Test 2 CSI process exceeded that of Test 1 by 7.9%, underscoring the increased efficiency of Test 2. This efficiency was attributed to a 33.2% lower oil saturation after the waterflooding process in Test 2 compared to Test 1. The positive impact of waterflooding on CO2-based CSI processes extended to Test 3, where the oil recovery factor of the CSI phase following waterflooding increased by 7.1% compared to the pre-waterflooding CSI phase. After nanoparticle solution flooding, the subsequent CSI phase yielded an additional 5.9% original oil in place (OOIP), demonstrating the nanoparticles' capacity to enhance foam stability even after multiple second oil recovery (SOR)/ enhanced oil recovery (EOR) processes. As the combined process progressed, the instantaneous gas-oil-ratio increased, facilitated by expanded space for CO2 injection amid heavy oil production. The amalgamated process achieved an impressive total oil recovery factor of 69.5%, more than doubling that of the CSI process in isolation.
{"title":"Enhancing Performance of Co2-Based CSI Process by Water Flooding and/or Nanoparticle Solution Flooding","authors":"Yishu Li, Zhongwei Du, Bo Wang, Jiasheng Ding, Fanhua Zeng","doi":"10.2118/218082-ms","DOIUrl":"https://doi.org/10.2118/218082-ms","url":null,"abstract":"\u0000 Foamy oil flow is a pivotal aspect of the cyclic solvent injection (CSI) process, yet the influence of water and foam stabilizers, such as nanoparticles, on its efficacy remains insufficiently elucidated. Consequently, a profound comprehension of how waterflooding and nanoparticles impact CSI performance is imperative for advancing oil recovery strategies. This study conducted a meticulously designed experimental investigation to investigate the roles of water and nanoparticles in a CO2-based CSI process. Three distinct tests were executed utilizing a cylindrical sandpack at varying injection pressures. Test 1 entailed a standard CO2-based CSI process for baseline comparison. Test 2 involved a waterflooding process with an injection volume of 1.5 PV, succeeded by a CO2-based CSI process. Test 3 featured a hybrid process comprising the sequence: CSI-waterflooding-CSI-Nanoparticle solution flooding-CSI. Key parameters including injection rate, injection volume, sandpack pressure, production rate, cumulative production, and water cut were meticulously monitored and recorded. Thorough data analytics were then employed to scrutinize the impact of water and nanoparticles, identifying mechanisms for enhancing the CSI process. Laboratory results revealed that the total oil recovery in Test 2 CSI process exceeded that of Test 1 by 7.9%, underscoring the increased efficiency of Test 2. This efficiency was attributed to a 33.2% lower oil saturation after the waterflooding process in Test 2 compared to Test 1. The positive impact of waterflooding on CO2-based CSI processes extended to Test 3, where the oil recovery factor of the CSI phase following waterflooding increased by 7.1% compared to the pre-waterflooding CSI phase. After nanoparticle solution flooding, the subsequent CSI phase yielded an additional 5.9% original oil in place (OOIP), demonstrating the nanoparticles' capacity to enhance foam stability even after multiple second oil recovery (SOR)/ enhanced oil recovery (EOR) processes. As the combined process progressed, the instantaneous gas-oil-ratio increased, facilitated by expanded space for CO2 injection amid heavy oil production. The amalgamated process achieved an impressive total oil recovery factor of 69.5%, more than doubling that of the CSI process in isolation.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285085","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Pugh, J. Kennedy, N. Morris, A. Haluszka, D. Abbey
Confined saline aquifers, often associated with hydrocarbon production, are an emerging source of lithium in the global market. They represent a new type of deposit, and there is a need to develop standards and guidelines for resource and reserve estimation to account for the unique characteristics and challenges of these deposits. This case study demonstrates the application of a new methodology for estimating resource volumes for confined saline aquifers, drawing on technical reports completed for the purposes of Canadian securities and exchange regulations in 2022-2023. As confined saline aquifers are often associated with hydrocarbon production, this methodology is of value for both existing oil and gas companies (who may have mineral resource present in their associated water production) and emerging mineral companies seeking to develop brine-hosted lithium projects.
{"title":"Mining a Liquid: Case Study for Resource Evaluation Methodology in a Confined Saline Aquifer, Bashaw District, Central Alberta, Canada","authors":"K. Pugh, J. Kennedy, N. Morris, A. Haluszka, D. Abbey","doi":"10.2118/218075-ms","DOIUrl":"https://doi.org/10.2118/218075-ms","url":null,"abstract":"\u0000 Confined saline aquifers, often associated with hydrocarbon production, are an emerging source of lithium in the global market. They represent a new type of deposit, and there is a need to develop standards and guidelines for resource and reserve estimation to account for the unique characteristics and challenges of these deposits.\u0000 This case study demonstrates the application of a new methodology for estimating resource volumes for confined saline aquifers, drawing on technical reports completed for the purposes of Canadian securities and exchange regulations in 2022-2023. As confined saline aquifers are often associated with hydrocarbon production, this methodology is of value for both existing oil and gas companies (who may have mineral resource present in their associated water production) and emerging mineral companies seeking to develop brine-hosted lithium projects.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"4 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395912","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}
M. Bataee, K. V. Rajandran, M. Soh, J. B. Ruvalcaba, Z. Hamdi, R. Carter
This study investigates the sustainable utilization of CO2 for energy extraction from geothermal reservoirs. Geothermal energy is a reliable and renewable source, but its efficiency can be enhanced through innovative approaches. The concept of utilizing CO2 as a working fluid in geothermal systems holds promise due to its favorable thermodynamic properties and potential for CO2 capture and storage. This research aims to explore the feasibility and benefits of using CO2 for energy extraction from geothermal reservoirs. The study combines theoretical modeling and numerical simulations to assess the performance of CO2-based geothermal systems. A conceptual framework is developed, considering the thermodynamic behavior of CO2 and its interactions with the subsurface reservoir. The simulations involve reservoir characterization, fluid flow analysis, and heat transfer calculations, taking into account various operational parameters and system configurations. The results demonstrate the potential of utilizing CO2 for energy extraction from geothermal reservoirs. The simulations reveal enhanced heat transfer efficiency and increased power generation when compared to traditional geothermal systems. The utilization of CO2 as a working fluid facilitates higher thermal efficiencies, lower greenhouse gas emissions, and improved overall system performance. The results also highlight the importance of proper reservoir characterization and operational optimization for maximizing energy extraction potential. The findings of this study emphasize the sustainable and efficient utilization of CO2 for energy extraction in geothermal systems. By employing CO2 as a working fluid, geothermal power generation can be significantly enhanced, contributing to a more sustainable and carbon-neutral energy sector. The outcomes of this research provide insights into the technical feasibility and environmental advantages of CO2-based geothermal systems, serving as a basis for further development and implementation of this innovative approach. The study contributes to the ongoing efforts in harnessing renewable energy sources and reducing carbon emissions, advancing the field of geothermal energy and promoting a sustainable energy transition.
{"title":"Utilizing CO2 for Energy Extraction from Geothermal Reservoirs in the Baram Basin, Sarawak Using Numerical Reservoir Simulation Based on Analogue Data","authors":"M. Bataee, K. V. Rajandran, M. Soh, J. B. Ruvalcaba, Z. Hamdi, R. Carter","doi":"10.2118/218096-ms","DOIUrl":"https://doi.org/10.2118/218096-ms","url":null,"abstract":"\u0000 This study investigates the sustainable utilization of CO2 for energy extraction from geothermal reservoirs. Geothermal energy is a reliable and renewable source, but its efficiency can be enhanced through innovative approaches. The concept of utilizing CO2 as a working fluid in geothermal systems holds promise due to its favorable thermodynamic properties and potential for CO2 capture and storage. This research aims to explore the feasibility and benefits of using CO2 for energy extraction from geothermal reservoirs. The study combines theoretical modeling and numerical simulations to assess the performance of CO2-based geothermal systems. A conceptual framework is developed, considering the thermodynamic behavior of CO2 and its interactions with the subsurface reservoir. The simulations involve reservoir characterization, fluid flow analysis, and heat transfer calculations, taking into account various operational parameters and system configurations. The results demonstrate the potential of utilizing CO2 for energy extraction from geothermal reservoirs. The simulations reveal enhanced heat transfer efficiency and increased power generation when compared to traditional geothermal systems. The utilization of CO2 as a working fluid facilitates higher thermal efficiencies, lower greenhouse gas emissions, and improved overall system performance. The results also highlight the importance of proper reservoir characterization and operational optimization for maximizing energy extraction potential. The findings of this study emphasize the sustainable and efficient utilization of CO2 for energy extraction in geothermal systems. By employing CO2 as a working fluid, geothermal power generation can be significantly enhanced, contributing to a more sustainable and carbon-neutral energy sector. The outcomes of this research provide insights into the technical feasibility and environmental advantages of CO2-based geothermal systems, serving as a basis for further development and implementation of this innovative approach. The study contributes to the ongoing efforts in harnessing renewable energy sources and reducing carbon emissions, advancing the field of geothermal energy and promoting a sustainable energy transition.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"31 S105","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395170","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}
Offshore production system assessment is very important to maintain and optimize wells performance including ESP, gas lift, natural flow wells, flow line network and de-bottlenecking. The oil production gain from optimization will add great value in maintaining production targets and increase the Maximum Sustained Capacity (MSC) which is the maximum production rate can be produced for stable period within a notice of not more than two months. Offshore optimization includes new facilities such as flow stations, gas lift capacity, introducing new ESP wells, laying down new flow lines and additional transmission lines. Production optimization changes warrant an update and reassessment of the production model used for optimization and de-bottleneck studies including the review and evaluation of the existing well & network models to develop a clear strategy and to update the production model with optimization. The optimal lifting rate according to the well level can be determined by varying the gas lifting rate and comparing its rate of change with the minimum economic rate of change which can be obtained during the ability tests for each well considering changing the gas lift injection rate to sense the impact on the production rate with the best increment to get within the given gas injection rate. In order to assist oil and gas field workers in daily activities and to optimize the time they spent checking and opening closed wells which is a tedious job especially during rough sea conditions and when there is no available means of transportation, a new way of tracking wells production throughout the flow lines pressure feeding the flow station are presented and examined in order to focus on some areas to regain the production loss due to wells shut in suffering from the back pressure exerted by other wells on the stream. Gathering data from several flow lines to build a database which will be much appreciated especially for offshore fields where there is no Supervisory Control and Data Acquisition "SCADA" Units during rough sea conditions and in emergency cases to overcome production loss.
{"title":"Correlating Flow Station Parameters with Oil Wells Performance","authors":"Sultan. A. AlAklubi","doi":"10.2118/218121-ms","DOIUrl":"https://doi.org/10.2118/218121-ms","url":null,"abstract":"\u0000 Offshore production system assessment is very important to maintain and optimize wells performance including ESP, gas lift, natural flow wells, flow line network and de-bottlenecking. The oil production gain from optimization will add great value in maintaining production targets and increase the Maximum Sustained Capacity (MSC) which is the maximum production rate can be produced for stable period within a notice of not more than two months. Offshore optimization includes new facilities such as flow stations, gas lift capacity, introducing new ESP wells, laying down new flow lines and additional transmission lines. Production optimization changes warrant an update and reassessment of the production model used for optimization and de-bottleneck studies including the review and evaluation of the existing well & network models to develop a clear strategy and to update the production model with optimization. The optimal lifting rate according to the well level can be determined by varying the gas lifting rate and comparing its rate of change with the minimum economic rate of change which can be obtained during the ability tests for each well considering changing the gas lift injection rate to sense the impact on the production rate with the best increment to get within the given gas injection rate.\u0000 In order to assist oil and gas field workers in daily activities and to optimize the time they spent checking and opening closed wells which is a tedious job especially during rough sea conditions and when there is no available means of transportation, a new way of tracking wells production throughout the flow lines pressure feeding the flow station are presented and examined in order to focus on some areas to regain the production loss due to wells shut in suffering from the back pressure exerted by other wells on the stream. Gathering data from several flow lines to build a database which will be much appreciated especially for offshore fields where there is no Supervisory Control and Data Acquisition \"SCADA\" Units during rough sea conditions and in emergency cases to overcome production loss.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"119 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284987","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 energy has emerged as a promising renewable energy source with its continuous availability and independence from weather conditions. However, the development of geothermal wells faces various challenges that limit its widespread adoption. One of these challenges is the decline in the efficiency of geothermal wells over time due to the reduction in permeability and scale formation. Acidizing is a common technique used to enhance productivity of the wells. During the stimulation of these geothermal wells, there is a need to temporarily block the high permeability zones for sufficient duration to selectively direct the injected acid to target formation. This study introduces a novel approach for the temporary isolation of high-permeability zones in geothermal wells using a specially formulated diversion fluid. This fluid is a mixture of a polymer solution with nanoparticles and crosslinking agents. The study primarily explores the efficiency of hydrolyzed polyacrylamide (HPAM) polymer solutions at various concentrations (5,000 – 30,000 ppm) and nanoparticle levels (100 – 3,000 ppm). The goal is to determine the optimal concentration for temperatures ranging from 100 to 250°C, examining different polymer, nanoparticle, and crosslinker combinations. Rheology measurements and static tests were conducted to assess the behavior of the prepared fluid both before and after heating. The viscosity of the solution was examined versus both time and shear rate at a wide temperature range of 25 to 120°C. Static tests were performed to evaluate the thermal stability of the solutions, as well as gelation time and the time required for the gel to completely break down. These tests were conducted at various temperatures ranging from 100 to 250°C. The objective was to assess the effectiveness of the formed gel plug in temporarily blocking the flow in addition to the gel’s ability to return to a liquid state within three to five days. The results obtained from this study showed successful development of an innovative fluid for temporary isolation, effective up to 200 - 250°C. This achievement was made possible by combining nanoparticles with hydrolyzed polyacrylamide polymer solutions after adding metal-based chromium, resulting in a physically crosslinked gel due to complexation between the metal and carboxylic acid groups on HPAM. Importantly, the gel plug can revert to a liquid state under reservoir conditions, eliminating the need for external breaker chemicals. This feature simplifies the removal of the gel plug post its isolation function. The unique aspect of this study is addressing the problem of early crosslinking at high temperatures, by introducing metal lactate CLD-Z as a crosslinker delayer agent. Five different types of HPAM polymers were tested in this project and it was found that the polymer (A) exhibited a viscosity below 100 centipoise (cp) at ambient conditions and 300 rpm with concentrations up to 15,000 ppm, whereas polymer (B) i
{"title":"Advancing Isolation Techniques for Geothermal Wells: Development of Polymer and Nanoparticle System","authors":"A. M. Shehata, N. Kalia, R. Comer","doi":"10.2118/218052-ms","DOIUrl":"https://doi.org/10.2118/218052-ms","url":null,"abstract":"\u0000 Geothermal energy has emerged as a promising renewable energy source with its continuous availability and independence from weather conditions. However, the development of geothermal wells faces various challenges that limit its widespread adoption. One of these challenges is the decline in the efficiency of geothermal wells over time due to the reduction in permeability and scale formation. Acidizing is a common technique used to enhance productivity of the wells. During the stimulation of these geothermal wells, there is a need to temporarily block the high permeability zones for sufficient duration to selectively direct the injected acid to target formation.\u0000 This study introduces a novel approach for the temporary isolation of high-permeability zones in geothermal wells using a specially formulated diversion fluid. This fluid is a mixture of a polymer solution with nanoparticles and crosslinking agents. The study primarily explores the efficiency of hydrolyzed polyacrylamide (HPAM) polymer solutions at various concentrations (5,000 – 30,000 ppm) and nanoparticle levels (100 – 3,000 ppm). The goal is to determine the optimal concentration for temperatures ranging from 100 to 250°C, examining different polymer, nanoparticle, and crosslinker combinations.\u0000 Rheology measurements and static tests were conducted to assess the behavior of the prepared fluid both before and after heating. The viscosity of the solution was examined versus both time and shear rate at a wide temperature range of 25 to 120°C. Static tests were performed to evaluate the thermal stability of the solutions, as well as gelation time and the time required for the gel to completely break down. These tests were conducted at various temperatures ranging from 100 to 250°C. The objective was to assess the effectiveness of the formed gel plug in temporarily blocking the flow in addition to the gel’s ability to return to a liquid state within three to five days.\u0000 The results obtained from this study showed successful development of an innovative fluid for temporary isolation, effective up to 200 - 250°C. This achievement was made possible by combining nanoparticles with hydrolyzed polyacrylamide polymer solutions after adding metal-based chromium, resulting in a physically crosslinked gel due to complexation between the metal and carboxylic acid groups on HPAM. Importantly, the gel plug can revert to a liquid state under reservoir conditions, eliminating the need for external breaker chemicals. This feature simplifies the removal of the gel plug post its isolation function. The unique aspect of this study is addressing the problem of early crosslinking at high temperatures, by introducing metal lactate CLD-Z as a crosslinker delayer agent. Five different types of HPAM polymers were tested in this project and it was found that the polymer (A) exhibited a viscosity below 100 centipoise (cp) at ambient conditions and 300 rpm with concentrations up to 15,000 ppm, whereas polymer (B) i","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"35 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395427","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}
Michael Ellsworth, Rejish Joseph, Dylan Hematillake, C. Diaz-Goano
The replacement and maintenance of Electric Submersible Pumps (ESP) represents a significant operating expense for any in-situ Oil Sands operation. The goal at Suncor's in-situ operations is to effectively and efficiently manage ESP failures to lower costs, maintain production, reduce carbon emissions, and contribute to safe operations. This goal is in part, accomplished through a collection of software tools that automate and enhance Production Engineering workflows related to the management of over 300 ESPs. An overview of the overall digitalization effort, including information about the development and rationale behind the centralized ESP information and analytics database, various failure prediction tools and anomaly detection methodologies, and the application that delivers these solutions is discussed. The estimated impact of this effort is measured through accuracy. The ideas behind the effort have, both directly and indirectly, contributed to the increase in ESP run life, the decrease in ESP replacement time, the decrease in person-hours per ESP required for management, the increase in safe operations, and the increase to general well availability.
{"title":"Digitalizing the Management of Electric Submersible Pump Failures Through Failure Prevention and Post-Mortem Analysis Tools","authors":"Michael Ellsworth, Rejish Joseph, Dylan Hematillake, C. Diaz-Goano","doi":"10.2118/218124-ms","DOIUrl":"https://doi.org/10.2118/218124-ms","url":null,"abstract":"\u0000 The replacement and maintenance of Electric Submersible Pumps (ESP) represents a significant operating expense for any in-situ Oil Sands operation. The goal at Suncor's in-situ operations is to effectively and efficiently manage ESP failures to lower costs, maintain production, reduce carbon emissions, and contribute to safe operations. This goal is in part, accomplished through a collection of software tools that automate and enhance Production Engineering workflows related to the management of over 300 ESPs. An overview of the overall digitalization effort, including information about the development and rationale behind the centralized ESP information and analytics database, various failure prediction tools and anomaly detection methodologies, and the application that delivers these solutions is discussed. The estimated impact of this effort is measured through accuracy. The ideas behind the effort have, both directly and indirectly, contributed to the increase in ESP run life, the decrease in ESP replacement time, the decrease in person-hours per ESP required for management, the increase in safe operations, and the increase to general well availability.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"105 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285119","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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