R. Wibawa, Rosyadi Rosyadi, Maulirany Nancy, Raden Irfani Hasya Fulki
Dynamometer card is one of the vital surveillances for Sucker Rod Pump (SRP) performance monitoring in Duri field. Even though the field produces a massive number of cards, they come with no label or interpretation about the pump conditions based on the card shape. Self-supervised learning (SSL) consists of a pretext task that trains feature extractors by using unlabeled data as opposed to supervised learning, that requires a lot of effort in labeling data which is time consuming and costly. This paper evaluates the performance of a feature extractor, Alexnet, that is trained by using several pretext task techniques. This study used around 660,000 unlabeled cards while a small amount of labeled data was used for evaluation purposes using linear evaluation protocol. The result showed that the trained Alexnet using Pretext-Invariant Representation Learning (PIRL) with jigsaw has better performance by 6% compared to the pre-trained ImageNet model. Further fine-tuning process by using labeled data could achieve 93% accuracy. The model was also tested using fresh data and the result was compared to the expert's interpretation. This approach can potentially add more types of rod pump problems to detect in the Duri field with considerable precision. In addition, the new approach could improve the current method of detecting more SRP with valve leaking problems.
{"title":"Unlocking the Potential of Unlabeled Data in Building Deep Learning Model for Dynamometer Cards Classification by Using Self-Supervised Learning","authors":"R. Wibawa, Rosyadi Rosyadi, Maulirany Nancy, Raden Irfani Hasya Fulki","doi":"10.2523/iptc-23026-ea","DOIUrl":"https://doi.org/10.2523/iptc-23026-ea","url":null,"abstract":"\u0000 Dynamometer card is one of the vital surveillances for Sucker Rod Pump (SRP) performance monitoring in Duri field. Even though the field produces a massive number of cards, they come with no label or interpretation about the pump conditions based on the card shape. Self-supervised learning (SSL) consists of a pretext task that trains feature extractors by using unlabeled data as opposed to supervised learning, that requires a lot of effort in labeling data which is time consuming and costly. This paper evaluates the performance of a feature extractor, Alexnet, that is trained by using several pretext task techniques. This study used around 660,000 unlabeled cards while a small amount of labeled data was used for evaluation purposes using linear evaluation protocol. The result showed that the trained Alexnet using Pretext-Invariant Representation Learning (PIRL) with jigsaw has better performance by 6% compared to the pre-trained ImageNet model. Further fine-tuning process by using labeled data could achieve 93% accuracy. The model was also tested using fresh data and the result was compared to the expert's interpretation. This approach can potentially add more types of rod pump problems to detect in the Duri field with considerable precision. In addition, the new approach could improve the current method of detecting more SRP with valve leaking problems.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126486802","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}
Ainash Shabdirova, A. Kozhagulova, Minh Nguyen, Yong Zhao
The objective of the paper is to discuss the application of different Machine Learning (ML) algorithms to predict sand volume during oil production from a weak sandstone reservoir in Kazakhstan. The field data consists of the data set from 10 wells comprising such parameters as fluid flow rate, water cut value, depth of the reservoir, and thickness of the producing zone. Six different algorithms were applied and root-mean-square error (RMSE) was used to compare different algorithms. The algorithms were trained with the data from 8 wells and tested on the data from the other two wells. Variable selection methods were used to identify the most important input parameters. The results show that the KNN algorithm has the best performance. The analysis suggests that the ML algorithm can be successfully used for the prediction of transient and non-transient sand production behavior. The algorithm is especially useful for transient sand production, where sand burst is followed by abrupt decline and finally stops. The results show that the algorithm can fairly predict the peak sand volumes which is useful for sand management measures. The variable selection studies suggest that water cut value and fluid flow rate are the most important parameters both for the sand volume amount and accuracy of the algorithm. The novelty of the paper is an attempt to predict sand volume using ML algorithms while existing studies focused only on sanding onset prediction.
{"title":"A Novel Approach to Sand Volume Prediction Using Machine Learning Algorithms","authors":"Ainash Shabdirova, A. Kozhagulova, Minh Nguyen, Yong Zhao","doi":"10.2523/iptc-22770-ea","DOIUrl":"https://doi.org/10.2523/iptc-22770-ea","url":null,"abstract":"\u0000 The objective of the paper is to discuss the application of different Machine Learning (ML) algorithms to predict sand volume during oil production from a weak sandstone reservoir in Kazakhstan. The field data consists of the data set from 10 wells comprising such parameters as fluid flow rate, water cut value, depth of the reservoir, and thickness of the producing zone. Six different algorithms were applied and root-mean-square error (RMSE) was used to compare different algorithms. The algorithms were trained with the data from 8 wells and tested on the data from the other two wells. Variable selection methods were used to identify the most important input parameters. The results show that the KNN algorithm has the best performance. The analysis suggests that the ML algorithm can be successfully used for the prediction of transient and non-transient sand production behavior. The algorithm is especially useful for transient sand production, where sand burst is followed by abrupt decline and finally stops. The results show that the algorithm can fairly predict the peak sand volumes which is useful for sand management measures. The variable selection studies suggest that water cut value and fluid flow rate are the most important parameters both for the sand volume amount and accuracy of the algorithm. The novelty of the paper is an attempt to predict sand volume using ML algorithms while existing studies focused only on sanding onset prediction.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116466039","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 details a slip-over design concept and challenges for the replacement of existing ageing offshore Well-Head (WH) fixed platforms for relatively shallow and deep-water fields applications. A cost-effective slip-over design concept for replacement of existing platforms and the utilization of existing wells with cost effective reduction and increased oil production has been developed. The design has been implemented repeatedly in relatively shallow water offshore fields that requires minimum offshore execution work schedule with minimum installation risk, optimized shutdown duration and minimum loss of oil production. Further enhancement of the design ensured any future plan for installation of a slipover platform in a relatively deeper water would overcome the requirement for a much bigger derrick vessel hook-height capacity mobilization. The new developed slipover structure design, which is based on Company's standardized, simplified and SIMOPS (simultaneous operations capable) (SSS) multi-bay four (4) legged jacket, is compliant with all the latest Company and applicable international standards, which involves the demolishing of existing structure together with the leg-through piles to a depth of between 1.5-2.0m below seabed and transported to reclamation site, while existing well conductors remain and are secured in place. A new slipover platform is installed over existing conductors with additional well slots design utilizing the same existing platform seabed location for increased production. A minimum shutdown requirement for installation, additional production potential and reduced CAPEX and OPEX are achieved. This design concept is also extended to a relatively deep-water fields application by either, the mobilization of a higher installation derrick vessel hook-height lift elevation for utilization over existing free-standing wells or the use of a two-piece stacked jacket design.
{"title":"New Innovative Approach to the Upgrade of Ageing Existing Offshore WellHead Platforms","authors":"Morhaf W. Jandali, Khamis M. Hajri","doi":"10.2523/iptc-22737-ms","DOIUrl":"https://doi.org/10.2523/iptc-22737-ms","url":null,"abstract":"\u0000 This paper details a slip-over design concept and challenges for the replacement of existing ageing offshore Well-Head (WH) fixed platforms for relatively shallow and deep-water fields applications. A cost-effective slip-over design concept for replacement of existing platforms and the utilization of existing wells with cost effective reduction and increased oil production has been developed. The design has been implemented repeatedly in relatively shallow water offshore fields that requires minimum offshore execution work schedule with minimum installation risk, optimized shutdown duration and minimum loss of oil production. Further enhancement of the design ensured any future plan for installation of a slipover platform in a relatively deeper water would overcome the requirement for a much bigger derrick vessel hook-height capacity mobilization. The new developed slipover structure design, which is based on Company's standardized, simplified and SIMOPS (simultaneous operations capable) (SSS) multi-bay four (4) legged jacket, is compliant with all the latest Company and applicable international standards, which involves the demolishing of existing structure together with the leg-through piles to a depth of between 1.5-2.0m below seabed and transported to reclamation site, while existing well conductors remain and are secured in place. A new slipover platform is installed over existing conductors with additional well slots design utilizing the same existing platform seabed location for increased production. A minimum shutdown requirement for installation, additional production potential and reduced CAPEX and OPEX are achieved. This design concept is also extended to a relatively deep-water fields application by either, the mobilization of a higher installation derrick vessel hook-height lift elevation for utilization over existing free-standing wells or the use of a two-piece stacked jacket design.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"87 6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115057254","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}
Yeek Huey Ho, Siti Rodhiah Fazilah, Jesus Nava Bastidas, Amirul Adha Bin Amsidom, E. A. Rosland, Khairul Nizam Idris, R. Masoudi, Kukuh Trjangganung, Zahrah Mohd Khair, Mohamad Syafiq majid, Ahmad Nabil Subandi, Tharushana Chandaran
More than 50% of Malaysia fields are matured or at its late life stage. These fields are mostly highly dependent on gas lift as the artificial lift method to maximize well potential and reserves recovery. Many of these fields are presently facing matured field operational challenges such as high water cut, shortage of gas lift supply, reservoir pressure depletion and aging facilities. As host authority for all hydrocarbon resources in Malaysia, PETRONAS Malaysia Petroleum Management (MPM) has initiated a Malaysia- wide effort to improve the production rate and recovery of hydrocarbon by expanding the usage of Electric Submersible Pump (ESP) as an alternative artificial lift method. ESP is an alternative artificial lift method that has been successfully pilot deployment. This paper focuses on the strategy of ESP replications at Malaysia to address production decline and extending well life through various enabler to support the target. PETRONAS has identified 10% of producing wells in Malaysia that will benefit from ESP technology, resulting in 6% incremental production. Subsequently, PETRONAS embarking ESP Feasibility Study with Solution Partner to mature ESP opportunities basket in integrated approach surface and subsurface and acts as an enabler for PAC to evaluate future fields for ESP replications. There are four main scopes in Feasibility Study which are, (i) Data Gathering and Well Screening, (ii) Potential Candidate Identification, (iii) Maturation of Opportunities Proposal and (iv) cost effective solution for ESP implementation. At the same time, ESP Integrated Contract which will serve as end-to-end solution for all PACs, is being developed by MPM as a key enabler to enhance ESP replications via more volume of work, lower cost, and improved lifecycle efficiency. There were five fields were under the ESP Feasibility Studies where comprehensive of subsurface and surface study were conducted. More than 500 strings were evaluated. A 50 well proposals were completed and the ESP opportunities to be implemented by phases to address production decline and to increase well life, leveraging on ESP Integrated Contract to create more value to PETRONAS and PAC. The feasibility study has also guided PETRONAS in candidate prioritization. Long term roadmap on ESP replications was developed to fully capitalize on ESP Technology to enhance Malaysia production and reserves monetization by creating the right ESP eco-system for the Oil & Gas Industry. The feasibility Studies approach enable future ESP studies in Malaysia fields.
马来西亚超过50%的油田已经成熟或处于后期开采阶段。这些油田大多高度依赖气举作为人工举升方法，以最大限度地提高油井潜力和储量采收率。其中许多油田目前面临着高含水、气举供应短缺、储层压力耗尽和设施老化等成熟的油田运营挑战。作为马来西亚所有油气资源的管理机构，马来西亚国家石油公司(PETRONAS Malaysia Petroleum Management，简称MPM)在马来西亚范围内开展了一项努力，通过扩大使用电潜泵(ESP)作为人工举升的替代方法，来提高油气的产量和采收率。ESP是一种人工举升的替代方法，已经成功进行了试运行。本文重点介绍了马来西亚的ESP复制策略，通过各种使能剂来解决产量下降问题，延长井寿命。马来西亚国家石油公司已经确定马来西亚10%的生产井将受益于ESP技术，从而使产量增加6%。随后，马来西亚国家石油公司与解决方案合作伙伴一起进行了ESP可行性研究，以成熟地面和地下综合方法的ESP机会篮子，并作为PAC评估未来油田ESP复制的推动因素。可行性研究的四个主要范围是:(i)数据收集和井筛选;(ii)潜在候选井识别;(iii)成熟机会建议;(iv)实施ESP的经济有效解决方案。与此同时，MPM正在开发的ESP集成合同将作为所有pac的端到端解决方案，通过更大的工作量、更低的成本和更高的生命周期效率来增强ESP复制能力。有五个油田正在进行ESP可行性研究，并进行了全面的地下和地面研究。超过500个字符串被评估。目前已经完成了50个井建议书，并将分阶段实施ESP，以解决产量下降和延长井寿命的问题，利用ESP集成合同为PETRONAS和PAC创造更多价值。可行性研究还指导了PETRONAS对候选项目的优先排序。为了充分利用ESP技术，通过为石油和天然气行业创建合适的ESP生态系统，提高马来西亚的产量和储量货币化，制定了ESP复制的长期路线图。可行性研究方法有助于未来在马来西亚油田进行ESP研究。
{"title":"Shifting Focus to Electrical Submersible Pump (ESP) Technology to Enhance Well Productivity and Recovery in Malaysia Fields","authors":"Yeek Huey Ho, Siti Rodhiah Fazilah, Jesus Nava Bastidas, Amirul Adha Bin Amsidom, E. A. Rosland, Khairul Nizam Idris, R. Masoudi, Kukuh Trjangganung, Zahrah Mohd Khair, Mohamad Syafiq majid, Ahmad Nabil Subandi, Tharushana Chandaran","doi":"10.2523/iptc-22792-ms","DOIUrl":"https://doi.org/10.2523/iptc-22792-ms","url":null,"abstract":"\u0000 More than 50% of Malaysia fields are matured or at its late life stage. These fields are mostly highly dependent on gas lift as the artificial lift method to maximize well potential and reserves recovery. Many of these fields are presently facing matured field operational challenges such as high water cut, shortage of gas lift supply, reservoir pressure depletion and aging facilities.\u0000 As host authority for all hydrocarbon resources in Malaysia, PETRONAS Malaysia Petroleum Management (MPM) has initiated a Malaysia- wide effort to improve the production rate and recovery of hydrocarbon by expanding the usage of Electric Submersible Pump (ESP) as an alternative artificial lift method. ESP is an alternative artificial lift method that has been successfully pilot deployment.\u0000 This paper focuses on the strategy of ESP replications at Malaysia to address production decline and extending well life through various enabler to support the target. PETRONAS has identified 10% of producing wells in Malaysia that will benefit from ESP technology, resulting in 6% incremental production. Subsequently, PETRONAS embarking ESP Feasibility Study with Solution Partner to mature ESP opportunities basket in integrated approach surface and subsurface and acts as an enabler for PAC to evaluate future fields for ESP replications.\u0000 There are four main scopes in Feasibility Study which are, (i) Data Gathering and Well Screening, (ii) Potential Candidate Identification, (iii) Maturation of Opportunities Proposal and (iv) cost effective solution for ESP implementation. At the same time, ESP Integrated Contract which will serve as end-to-end solution for all PACs, is being developed by MPM as a key enabler to enhance ESP replications via more volume of work, lower cost, and improved lifecycle efficiency.\u0000 There were five fields were under the ESP Feasibility Studies where comprehensive of subsurface and surface study were conducted. More than 500 strings were evaluated. A 50 well proposals were completed and the ESP opportunities to be implemented by phases to address production decline and to increase well life, leveraging on ESP Integrated Contract to create more value to PETRONAS and PAC. The feasibility study has also guided PETRONAS in candidate prioritization. Long term roadmap on ESP replications was developed to fully capitalize on ESP Technology to enhance Malaysia production and reserves monetization by creating the right ESP eco-system for the Oil & Gas Industry. The feasibility Studies approach enable future ESP studies in Malaysia fields.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129490464","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}
Consistent ethane recovery in the Natural Gas Liquefication (NGL) process is critical to achieve financial objectives of the NGL processing facility. Joule-Thompson (JT) effect in combination with various processes such as cascade-refrigeration or Residue-Split-Vapor (RSV) are being used in the industry to maximize the ethane recovery from the feed gas varying in the degree of 75% to more than 95%. Identifying the transient conditions and ensuring precise and accurate control throughout is of utmost importance. The transient conditions are categorized as start-up or a scheduled shutdown of the plant, and an upset of the plant. Any of these transient conditions may drive the plant in unstable state which would impact the ethane recovery drastically. This paper discusses a control algorithm that was developed to identify the transient states and to provide an accurate and stabilized control to keep the recovery above the target threshold. During the startup, a typical NGL plant will start its operation in JT mode and will slowly transition into a cooling mode by introducing turboexpander for example. During the shutdown mode, the plant slowly returns to JT mode by shutting down the turboexpanders. During the upset, the turboexpanders can accidently trip to force the plant in an unstable state. In transient states, an accurate control is required to precisely transfer the feed gas volume from turboexpanders to JT equipment or vice versa in a timely manner to minimize the impact such as loss of production or total plant trip. The proposed control algorithm predicts an upset in advance, captures the actual flow of the feed gas passing through the equipment prior to an upset and transforms the captured flow into an equivalent percentage opening of the backup equipment (in case of JT mode, the percentage opening of the JT valve and in case of turboexpander mode, the percentage opening of the Inlet Guided Vanes (IGVs)) to ensure the plant mass balance is maintained. The set point tracking feature of the algorithm ensures that when the normal Proportional Integral Derivative (PID) control is resumed the transfer of control is bump less to avoid any overshooting or undershooting of the overall plant pressure.
{"title":"Optimized NGL Control System with Actual Flow and Set Point Tracking Feature","authors":"Khurram Chishti","doi":"10.2523/iptc-22716-ms","DOIUrl":"https://doi.org/10.2523/iptc-22716-ms","url":null,"abstract":"\u0000 Consistent ethane recovery in the Natural Gas Liquefication (NGL) process is critical to achieve financial objectives of the NGL processing facility. Joule-Thompson (JT) effect in combination with various processes such as cascade-refrigeration or Residue-Split-Vapor (RSV) are being used in the industry to maximize the ethane recovery from the feed gas varying in the degree of 75% to more than 95%. Identifying the transient conditions and ensuring precise and accurate control throughout is of utmost importance. The transient conditions are categorized as start-up or a scheduled shutdown of the plant, and an upset of the plant. Any of these transient conditions may drive the plant in unstable state which would impact the ethane recovery drastically. This paper discusses a control algorithm that was developed to identify the transient states and to provide an accurate and stabilized control to keep the recovery above the target threshold. During the startup, a typical NGL plant will start its operation in JT mode and will slowly transition into a cooling mode by introducing turboexpander for example. During the shutdown mode, the plant slowly returns to JT mode by shutting down the turboexpanders. During the upset, the turboexpanders can accidently trip to force the plant in an unstable state. In transient states, an accurate control is required to precisely transfer the feed gas volume from turboexpanders to JT equipment or vice versa in a timely manner to minimize the impact such as loss of production or total plant trip. The proposed control algorithm predicts an upset in advance, captures the actual flow of the feed gas passing through the equipment prior to an upset and transforms the captured flow into an equivalent percentage opening of the backup equipment (in case of JT mode, the percentage opening of the JT valve and in case of turboexpander mode, the percentage opening of the Inlet Guided Vanes (IGVs)) to ensure the plant mass balance is maintained. The set point tracking feature of the algorithm ensures that when the normal Proportional Integral Derivative (PID) control is resumed the transfer of control is bump less to avoid any overshooting or undershooting of the overall plant pressure.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129894255","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 objective of this study is to understand the configuration of different deformation styles in post-salt sedimentary succession of Lower Congo Basin. Emphasis is placed on structural characteristics with respect to the thickness of salt and the geometry of the base of salt detachment. Owing to its weak visco-plastic properties, salt is very effective at decoupling deformation in pre- and post-salt sequences. Gravity and density driven deformation in the post-salt sediments is predominately controlled by salt thickness and changes in dip at the base of salt. Variations in these elements change across the basin which control the nature and timing of trap development. Using regional 2D and 3D seismic depth cubes, interpretation focused on the Aptian Salt and post-salt Cretaceous-Tertiary sedimentary succession. Here we map and identify various deformation styles in salt tectonics across the basin within which we observe consistent trap geometries which are containing hydrocarbons and resulting one of the prolific basins in the world for oil production. The post-salt sediments, present a classic example of gravity driven deformation associated with salt tectonics at a passive margin. Gravity driven structuration of (i) Extension, (ii) Translation and (iii) Compression can be observed along regional dip-sections. Through detailed mapping, various sub-domains provide an insight into the regional structural trends and tectonic evolution in the post-salt succession. Overall, ten structural domains have been identified from Shelf to distal basin along the regional dip section. Well defined structural domains can play a major role in classifying the trapping styles for hydrocarbon accumulations in post-salt successions. Identification of these domains provides a framework to de-risk different trap styles or highlights those traps which carry a higher trap risk. Timing of trap formation due to salt movement also plays a major role to further de-risk these traps. The main source rock for Post-salt section is located in Senonian interval, the charge modelling suggests the peak expulsion of hydrocarbon in Early Miocene time, therefore those traps formed in Oligocene to Early Miocene intervals have higher chance of trapping hydrocarbons, however traps formed from Mid – Miocene to younger levels have higher risk of trapping smaller or no hydrocarbons due to lack of charge availability.
{"title":"Post-Salt Structural Domains in Lower Congo Basin, Offhsore West Africa","authors":"Abdhes Kumar Upadhyay, J. Jaiswal, Syamir B Osman","doi":"10.2523/iptc-22839-ea","DOIUrl":"https://doi.org/10.2523/iptc-22839-ea","url":null,"abstract":"\u0000 The objective of this study is to understand the configuration of different deformation styles in post-salt sedimentary succession of Lower Congo Basin. Emphasis is placed on structural characteristics with respect to the thickness of salt and the geometry of the base of salt detachment.\u0000 Owing to its weak visco-plastic properties, salt is very effective at decoupling deformation in pre- and post-salt sequences. Gravity and density driven deformation in the post-salt sediments is predominately controlled by salt thickness and changes in dip at the base of salt. Variations in these elements change across the basin which control the nature and timing of trap development. Using regional 2D and 3D seismic depth cubes, interpretation focused on the Aptian Salt and post-salt Cretaceous-Tertiary sedimentary succession. Here we map and identify various deformation styles in salt tectonics across the basin within which we observe consistent trap geometries which are containing hydrocarbons and resulting one of the prolific basins in the world for oil production.\u0000 The post-salt sediments, present a classic example of gravity driven deformation associated with salt tectonics at a passive margin. Gravity driven structuration of (i) Extension, (ii) Translation and (iii) Compression can be observed along regional dip-sections. Through detailed mapping, various sub-domains provide an insight into the regional structural trends and tectonic evolution in the post-salt succession. Overall, ten structural domains have been identified from Shelf to distal basin along the regional dip section.\u0000 Well defined structural domains can play a major role in classifying the trapping styles for hydrocarbon accumulations in post-salt successions. Identification of these domains provides a framework to de-risk different trap styles or highlights those traps which carry a higher trap risk. Timing of trap formation due to salt movement also plays a major role to further de-risk these traps. The main source rock for Post-salt section is located in Senonian interval, the charge modelling suggests the peak expulsion of hydrocarbon in Early Miocene time, therefore those traps formed in Oligocene to Early Miocene intervals have higher chance of trapping hydrocarbons, however traps formed from Mid – Miocene to younger levels have higher risk of trapping smaller or no hydrocarbons due to lack of charge availability.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"110 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130221590","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}
Rahman Ashena, M. Madani, S. Sivanesan, V. Thiruchelvam
The thermal conductivity coefficient of the reservoir formation rock-cement-casing combination is an important parameter affecting the optimum circulation flow rate in open and closed-loop systems. Despite its importance, an accurate value of the thermal conductivity may not used in modeling due to the fact that either the thermal conductivity of the rock and cement is not measured in the lab to be accurately known, or the effect of cement and casing thermal conductivities on the net thermal conductivity is ignored. Therefore, this work investigates the effect of a change in the thermal conductivity on the net heat energy, the net power and the coefficient of performance (COP), at different circulation rates. The simulation results using CMG software for a high reservoir temperature shallow case study in Trindad and Tobago show that when the net thermal conductivity of 2 W/m/K is doubled, the net heat energy and power show minimal increase of up to ~1%. Such minimal increases are the case at all circulation rates, with the greatest heat increase occurring at the largest circulation rate. The minimal produced heat increase is attributed to the assumption of external reservoir temperature being at the nearest radius to the wellbore wall due to the fact that the high thermal conductivity of water in the fractures dominates and the fractures extend so far that the surface area for heat flow is very high. This is in accordance with previous research simulation results.
{"title":"Investigating the Effect of Thermal Conductivity on Geothermal Energy Production at Different Circulation Rates in an EGS Abandoned Case Study","authors":"Rahman Ashena, M. Madani, S. Sivanesan, V. Thiruchelvam","doi":"10.2523/iptc-22762-ea","DOIUrl":"https://doi.org/10.2523/iptc-22762-ea","url":null,"abstract":"\u0000 The thermal conductivity coefficient of the reservoir formation rock-cement-casing combination is an important parameter affecting the optimum circulation flow rate in open and closed-loop systems. Despite its importance, an accurate value of the thermal conductivity may not used in modeling due to the fact that either the thermal conductivity of the rock and cement is not measured in the lab to be accurately known, or the effect of cement and casing thermal conductivities on the net thermal conductivity is ignored. Therefore, this work investigates the effect of a change in the thermal conductivity on the net heat energy, the net power and the coefficient of performance (COP), at different circulation rates.\u0000 The simulation results using CMG software for a high reservoir temperature shallow case study in Trindad and Tobago show that when the net thermal conductivity of 2 W/m/K is doubled, the net heat energy and power show minimal increase of up to ~1%. Such minimal increases are the case at all circulation rates, with the greatest heat increase occurring at the largest circulation rate. The minimal produced heat increase is attributed to the assumption of external reservoir temperature being at the nearest radius to the wellbore wall due to the fact that the high thermal conductivity of water in the fractures dominates and the fractures extend so far that the surface area for heat flow is very high. This is in accordance with previous research simulation results.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"39 2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134094886","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 outlines an approach to optimize production from a shallow, low bottomhole pressure (BHP) reservoir in a mature onshore oilfield by the application of intermittent gas lift technology using Next Generation Internet of Things (IoT) based Intelligent Controller which works on industry 4.0 technologies. Enhanced software-based analysis, design, optimization, and automation has proved to be effective in enhancing the production rate from an existing gas lifted well. A selection criterion and workflow setup were devised for a major operator to enhance the efficiency of a gas lift system. Low production capacity wells were analyzed, designed, and troubleshooted from an intermittent gas lift technology perspective. It incorporated an IoT-based intelligent autonomous surface controller with a minimal change in downhole completion jewelry which eliminated the need of workovers, optimized oil production, reduced over injection of gas, diminished downtime, and improved the effectiveness of the overall petroleum production process beyond the capability of a conventional gas lift system. This system was successfully installed in wells with 2.375-in. tubing without any production deferment. A pilot project on sixteen wells for a major operator in the Middle East exhibited a significant improvement in well performance with an incremental gain of 600 bfpd along with savings of 5 mmscfd of injection gas. It is a cost-effective technology to optimize production and enhance the field value from existing wells. This paper considers cases in which an integrated software-automation portfolio helps in reviving and increasing ultimate recovery and recommends suitable actions which allow production engineers to analyze performance of reviving existing oil wells. With the increased complexity of mature fields, each next step to enhance recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.
{"title":"Intermittent Gas Lift Technology for Optimising Production from an Oilfield Using Next Generation IoT Based Intelligent Autonomous Controller","authors":"H. Tyagi","doi":"10.2523/iptc-22803-ea","DOIUrl":"https://doi.org/10.2523/iptc-22803-ea","url":null,"abstract":"\u0000 This paper outlines an approach to optimize production from a shallow, low bottomhole pressure (BHP) reservoir in a mature onshore oilfield by the application of intermittent gas lift technology using Next Generation Internet of Things (IoT) based Intelligent Controller which works on industry 4.0 technologies. Enhanced software-based analysis, design, optimization, and automation has proved to be effective in enhancing the production rate from an existing gas lifted well.\u0000 A selection criterion and workflow setup were devised for a major operator to enhance the efficiency of a gas lift system. Low production capacity wells were analyzed, designed, and troubleshooted from an intermittent gas lift technology perspective. It incorporated an IoT-based intelligent autonomous surface controller with a minimal change in downhole completion jewelry which eliminated the need of workovers, optimized oil production, reduced over injection of gas, diminished downtime, and improved the effectiveness of the overall petroleum production process beyond the capability of a conventional gas lift system.\u0000 This system was successfully installed in wells with 2.375-in. tubing without any production deferment. A pilot project on sixteen wells for a major operator in the Middle East exhibited a significant improvement in well performance with an incremental gain of 600 bfpd along with savings of 5 mmscfd of injection gas. It is a cost-effective technology to optimize production and enhance the field value from existing wells.\u0000 This paper considers cases in which an integrated software-automation portfolio helps in reviving and increasing ultimate recovery and recommends suitable actions which allow production engineers to analyze performance of reviving existing oil wells. With the increased complexity of mature fields, each next step to enhance recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132141629","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. F. Azman, Tunku Ahmad Farhan Tunku Kamaruddin, N. I. Mohmad, Luqman Hakim Zulkafli, Khiril Shahreza Salleh, Rizal Bakar
Field A consists of multi stacked reservoirs in high geological complexity and heterogeneity setting, with waterflooding has been the secondary drive mechanism for the past two decades. However, in recent years, the field experiencing significant production decline that warrant immediate mitigation plan and action. Therefore, this paper highlights challenges and best practices in rejuvenating water injected reservoir to improve field production by integrating geological re-interpretation, data acquisition and analytical evaluation. The reservoir is defined in deltaic environment with complex fluvial reservoir architecture. Despite no indication of structural trap or compartmentalization, there is significant variation in reservoir performance across the field indicates lateral heterogeneity that is affecting the areal sweep efficiency. Poor production-injection allocation data due to commingled production, aggravated by tubing leaks have hindered for an optimum formulation of waterflood strategy in the past. As part of the mitigation plan, depo-facies definition and stratigraphy boundaries were further refined, guided by well and reservoir pressure performance. Besides, inter-well tracer injection implementation proved to be the game changer - unfolded hydrodynamic connectivity and flow path of injected water understanding, established actual producer and injector pairing, and identified poor or unswept areas. It was supported by comprehensive analytical water injection performance analysis including Hall's Plot, Chan's Plot, Jordan's Plot as part of the routine surveillance activities to trigger any non-conformance. More aggressive well intervention also helped to identify and rectify well issues. As the outcomes, there is opportunity to increase water injection rate by 30% field wide by reactivating idle wells, converting producers to injector, and maximizing the existing injection within the safe fracture limit. The subsurface risks on fracture gradient uncertainty and sweep inefficiency due to water cycling to be mitigated via injectivity test with gradual injection, close monitoring of liquid rate handling at surface, and pattern balancing between injectors and producers. The liquid rate is expected to be restored and sustained nearing the historical peak, hence improve field production and temper the decline. This paper presents the best practices to address the challenges in a matured waterflood reservoirs, considering the complex geology setting. Understanding of the flood pattern from tracer analysis, supplemented by producer-injection performance assessment and well integrity status validation enabled water injection to be ramped up at the right area in strategically and safely manner.
{"title":"Rejuvenating Waterflood Reservoir in a Complex Geological Setting of a Matured Brown Field","authors":"M. F. Azman, Tunku Ahmad Farhan Tunku Kamaruddin, N. I. Mohmad, Luqman Hakim Zulkafli, Khiril Shahreza Salleh, Rizal Bakar","doi":"10.2523/iptc-23056-ea","DOIUrl":"https://doi.org/10.2523/iptc-23056-ea","url":null,"abstract":"\u0000 Field A consists of multi stacked reservoirs in high geological complexity and heterogeneity setting, with waterflooding has been the secondary drive mechanism for the past two decades. However, in recent years, the field experiencing significant production decline that warrant immediate mitigation plan and action. Therefore, this paper highlights challenges and best practices in rejuvenating water injected reservoir to improve field production by integrating geological re-interpretation, data acquisition and analytical evaluation.\u0000 The reservoir is defined in deltaic environment with complex fluvial reservoir architecture. Despite no indication of structural trap or compartmentalization, there is significant variation in reservoir performance across the field indicates lateral heterogeneity that is affecting the areal sweep efficiency. Poor production-injection allocation data due to commingled production, aggravated by tubing leaks have hindered for an optimum formulation of waterflood strategy in the past. As part of the mitigation plan, depo-facies definition and stratigraphy boundaries were further refined, guided by well and reservoir pressure performance. Besides, inter-well tracer injection implementation proved to be the game changer - unfolded hydrodynamic connectivity and flow path of injected water understanding, established actual producer and injector pairing, and identified poor or unswept areas. It was supported by comprehensive analytical water injection performance analysis including Hall's Plot, Chan's Plot, Jordan's Plot as part of the routine surveillance activities to trigger any non-conformance. More aggressive well intervention also helped to identify and rectify well issues.\u0000 As the outcomes, there is opportunity to increase water injection rate by 30% field wide by reactivating idle wells, converting producers to injector, and maximizing the existing injection within the safe fracture limit. The subsurface risks on fracture gradient uncertainty and sweep inefficiency due to water cycling to be mitigated via injectivity test with gradual injection, close monitoring of liquid rate handling at surface, and pattern balancing between injectors and producers. The liquid rate is expected to be restored and sustained nearing the historical peak, hence improve field production and temper the decline.\u0000 This paper presents the best practices to address the challenges in a matured waterflood reservoirs, considering the complex geology setting. Understanding of the flood pattern from tracer analysis, supplemented by producer-injection performance assessment and well integrity status validation enabled water injection to be ramped up at the right area in strategically and safely manner.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114355442","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}
P. Routh, A. Baumstein, Y. Cha, Soumya Nayak, Haiyang Wang, D. Tang, J. Barr, Alex Martinez
Elastic Full wave-field (eFWI) inversion is aimed at inferring physical properties of the subsurface directly from seismic data. Goal is use highest level of physics to produce reliable properties to impact upstream business decisions. We focus on elastic parameters particularly the ratio between pressure (P) and shear (S) wave velocity, Vp/Vs that can be indicative of the type of fluid present in subsurface reservoir and P-wave impedance, Ip to impact porosity estimation. Our eFWI methodology derives the wavelet directly from seismic shots rather than using well information. Using field examples we explain the eFWI workflow, outline key steps and provide analysis of the results. The first field example is from a structurally simple clastic setting. The second field example is from a complex sub-salt environment and is focused on differentiating net versus non-net in pre-salt carbonate reservoirs - a challenging problem when using narrow azimuth streamer data. The third field example is from a clastic setting and uses well information to scale the wavelet and is applicable in development and production settings. Our experiments with the two exploration style field examples show that it is possible to directly invert shot data to obtain geologically meaningful elastic properties useful in exploration and early development phases. However, challenges remain. The inverted Ip has higher fidelity compared to the Vp/Vs ratio. In fact, Ip is sufficiently accurate to be reliably used for porosity prediction. The eFWI Vp/Vs inversion results are only in qualitative agreement with well information (as a blind test) for the clastic example, but sufficient to discriminate the net versus non-net for the pre-salt example. A qualitative match may be insufficient to determine fluid type via rock property inversion without any well control. In an environment without well control, further research is needed to investigate the sensitivity of Vp/Vs and determine if data quality is a key factor, in addition to stabilizing the extraction of elastic parameters in a multi-parameter inverse problem. The novel aspect for our approach is in developing a practical eFWI methodology in 3D and working with raw seismic shots with very minimal processing. Examples from different geological settings and use of well versus no-well provide valuable insights into current application space and potential research direction on improvements to eFWI algorithm.
{"title":"Insights from Application of Elastic Full Wave-Field Inversion in Clastic and Sub-Salt Settings.","authors":"P. Routh, A. Baumstein, Y. Cha, Soumya Nayak, Haiyang Wang, D. Tang, J. Barr, Alex Martinez","doi":"10.2523/iptc-22783-ea","DOIUrl":"https://doi.org/10.2523/iptc-22783-ea","url":null,"abstract":"\u0000 Elastic Full wave-field (eFWI) inversion is aimed at inferring physical properties of the subsurface directly from seismic data. Goal is use highest level of physics to produce reliable properties to impact upstream business decisions. We focus on elastic parameters particularly the ratio between pressure (P) and shear (S) wave velocity, Vp/Vs that can be indicative of the type of fluid present in subsurface reservoir and P-wave impedance, Ip to impact porosity estimation.\u0000 Our eFWI methodology derives the wavelet directly from seismic shots rather than using well information. Using field examples we explain the eFWI workflow, outline key steps and provide analysis of the results. The first field example is from a structurally simple clastic setting. The second field example is from a complex sub-salt environment and is focused on differentiating net versus non-net in pre-salt carbonate reservoirs - a challenging problem when using narrow azimuth streamer data. The third field example is from a clastic setting and uses well information to scale the wavelet and is applicable in development and production settings.\u0000 Our experiments with the two exploration style field examples show that it is possible to directly invert shot data to obtain geologically meaningful elastic properties useful in exploration and early development phases. However, challenges remain. The inverted Ip has higher fidelity compared to the Vp/Vs ratio. In fact, Ip is sufficiently accurate to be reliably used for porosity prediction. The eFWI Vp/Vs inversion results are only in qualitative agreement with well information (as a blind test) for the clastic example, but sufficient to discriminate the net versus non-net for the pre-salt example. A qualitative match may be insufficient to determine fluid type via rock property inversion without any well control. In an environment without well control, further research is needed to investigate the sensitivity of Vp/Vs and determine if data quality is a key factor, in addition to stabilizing the extraction of elastic parameters in a multi-parameter inverse problem.\u0000 The novel aspect for our approach is in developing a practical eFWI methodology in 3D and working with raw seismic shots with very minimal processing. Examples from different geological settings and use of well versus no-well provide valuable insights into current application space and potential research direction on improvements to eFWI algorithm.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"150 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116357981","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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