The construction of Zhongyuan gas storage group takes the salt layer as the caprock. Therefore, the cementing quality of the sealed salt interval is a key factor in the construction of gas storage. The cement slurry was eroded by the salt gypsum layer during the migration of the salt layer, which affects the basic performance of cement slurry, resulting in the poor cementation quality between cement sheath and salt layer. In addition, the irregular borehole in the salt layer and the expansion of well diameter make the displacement efficiency poor in the cementing process, which restricts the cementing quality of this kind of wells. At present, due to the unsatisfactory cementing quality and low excellent rate of cementing quality in the salt layer during the construction of Wen 23 gas storage, the construction of gas storage cannot be completed as planned. Therefore, in order to ensure the successful construction and service life of gas storage, the cementing technology research of big-thickness salt layer in Zhongyuan Gas Storage Group is carried out. The salt resistant fluid loss reducer and retarder are selected through the project test, and the expansion early strength agent and toughening agent are selected. Through the compatibility research and the evaluation of the performance of cement slurry and the cementation strength of cement stone by the erosion of different salt content, a fresh-water-salt-resistant and ductile cement slurry system suitable for salt rock cementing is formed; In terms of cementing technology, we have developed well hole optimization technology, optimized leakage prevention technology in salt section and supporting high-quality sealing technology in salt layer, formed cementing technology and recommended practices for Wen 23 gas storage, and effectively ensured the primary success rate of cementing in Wen 23 gas storage. The research results of this subject have been successfully applied in 12 wells of Wen 23 gas storage and Wei 11 gas storage. The qualified rate of cementing quality has been increased from 96% to 100% and the excellent rate has been increased from 12% to 83.33%, which meets the requirements of gas storage for salt layer sealing quality and ensures the safe and efficient operation of Zhongyuan Gas Storage Group.
{"title":"Cementing Technology of Salt Layer in Wen23 Gas Storage","authors":"Xiaolong Ma, Huajie Liu, Meihua Huo, Heng Yang, Yuhuan Bu, Shenglai Guo, Hui Yin, Jiansheng Zhao","doi":"10.2523/iptc-22887-ms","DOIUrl":"https://doi.org/10.2523/iptc-22887-ms","url":null,"abstract":"\u0000 The construction of Zhongyuan gas storage group takes the salt layer as the caprock. Therefore, the cementing quality of the sealed salt interval is a key factor in the construction of gas storage. The cement slurry was eroded by the salt gypsum layer during the migration of the salt layer, which affects the basic performance of cement slurry, resulting in the poor cementation quality between cement sheath and salt layer. In addition, the irregular borehole in the salt layer and the expansion of well diameter make the displacement efficiency poor in the cementing process, which restricts the cementing quality of this kind of wells. At present, due to the unsatisfactory cementing quality and low excellent rate of cementing quality in the salt layer during the construction of Wen 23 gas storage, the construction of gas storage cannot be completed as planned. Therefore, in order to ensure the successful construction and service life of gas storage, the cementing technology research of big-thickness salt layer in Zhongyuan Gas Storage Group is carried out.\u0000 The salt resistant fluid loss reducer and retarder are selected through the project test, and the expansion early strength agent and toughening agent are selected. Through the compatibility research and the evaluation of the performance of cement slurry and the cementation strength of cement stone by the erosion of different salt content, a fresh-water-salt-resistant and ductile cement slurry system suitable for salt rock cementing is formed; In terms of cementing technology, we have developed well hole optimization technology, optimized leakage prevention technology in salt section and supporting high-quality sealing technology in salt layer, formed cementing technology and recommended practices for Wen 23 gas storage, and effectively ensured the primary success rate of cementing in Wen 23 gas storage. The research results of this subject have been successfully applied in 12 wells of Wen 23 gas storage and Wei 11 gas storage. The qualified rate of cementing quality has been increased from 96% to 100% and the excellent rate has been increased from 12% to 83.33%, which meets the requirements of gas storage for salt layer sealing quality and ensures the safe and efficient operation of Zhongyuan Gas Storage Group.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"65 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":"131991464","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}
A. Bardhan, Fahad Khan, H. Kesarwani, Sushipra Vats, Shivanjali Sharma, Shailesh Kumar
Improving water-based drilling fluid properties to mitigate instability issues at elevated temperatures is the need of the hour. In this study, industrially prepared silica nanoparticles (NPs) coated with AEAPTS ([3-(2-Aminoethylamino) propyl] trimethoxy silane) was used as an additive to enhance the rheology and control filtration of the water-based mud. Silica nanoparticles were coated separately in a two-step process, which involved the addition of a hydroxyl group first and then coating with AEAPTS. To check its applicability in water-based drilling fluids rheological and filtration tests were done with varying NP concentrations of 0.2, 0.3, and 0.4 w/v %. The rheology values of the mud samples were recorded both before and after the thermal aging of mud in the roller oven at 105°C for 16 hours. The filtration test was carried out according to API standards with 100 psi differential pressure for 30 minutes. The silane coating over the silica NPs was confirmed with the shifting in the peaks of the FTIR (Fourier Transform Infrared) spectra of the sample. Both the plastic viscosity (PV) and the apparent viscosity (AV) of the drilling fluid were found to be increasing with silane-coated silica nanoparticles’ inclusion when tested at 30°C and 60°C. The degradation in the rheology of the base mud without nanoparticles after thermal aging was found to be around 60 % which was reduced to around 20 % with the addition of the coated silica nanoparticle. Also, a remarkable reduction in the filtrate volume, when compared with base mud, was achieved with the addition of the silane coated NP in the mud. The results show that the novel AEAPT silane-coated silica NPs can be used as a rheology modifier and filtration control additive in water-based drilling fluid for high-temperature drilling applications.
{"title":"Performance Evaluation of Novel Silane Coated Nanoparticles as an Additive for High-Performance Drilling Fluid Applications","authors":"A. Bardhan, Fahad Khan, H. Kesarwani, Sushipra Vats, Shivanjali Sharma, Shailesh Kumar","doi":"10.2523/iptc-22878-ms","DOIUrl":"https://doi.org/10.2523/iptc-22878-ms","url":null,"abstract":"\u0000 Improving water-based drilling fluid properties to mitigate instability issues at elevated temperatures is the need of the hour. In this study, industrially prepared silica nanoparticles (NPs) coated with AEAPTS ([3-(2-Aminoethylamino) propyl] trimethoxy silane) was used as an additive to enhance the rheology and control filtration of the water-based mud. Silica nanoparticles were coated separately in a two-step process, which involved the addition of a hydroxyl group first and then coating with AEAPTS. To check its applicability in water-based drilling fluids rheological and filtration tests were done with varying NP concentrations of 0.2, 0.3, and 0.4 w/v %. The rheology values of the mud samples were recorded both before and after the thermal aging of mud in the roller oven at 105°C for 16 hours. The filtration test was carried out according to API standards with 100 psi differential pressure for 30 minutes. The silane coating over the silica NPs was confirmed with the shifting in the peaks of the FTIR (Fourier Transform Infrared) spectra of the sample. Both the plastic viscosity (PV) and the apparent viscosity (AV) of the drilling fluid were found to be increasing with silane-coated silica nanoparticles’ inclusion when tested at 30°C and 60°C. The degradation in the rheology of the base mud without nanoparticles after thermal aging was found to be around 60 % which was reduced to around 20 % with the addition of the coated silica nanoparticle. Also, a remarkable reduction in the filtrate volume, when compared with base mud, was achieved with the addition of the silane coated NP in the mud. The results show that the novel AEAPT silane-coated silica NPs can be used as a rheology modifier and filtration control additive in water-based drilling fluid for high-temperature drilling applications.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"79 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":"132228878","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}
Alhadi Zahmuwl, Kamaljeet Singh, E. Wielemaker, S. Bose, S. Zeroug, Ali Assad, R. Loov, Gulnara Ishberdina, L. Martini
Abandoning a well after it reaches the end of its life cycle requires a barrier evaluation operation across multiple strings. The traditional method for barrier evaluation requires exposing the outer casing by a cut and pull or section mill of the inner casing so that the outer casing can be logged, to verify the barrier seal. The cut and pull and subsequent inner casing/tubing recovery or section milling operations are costly and time consuming, often lasting for several days, thus increasing the overall plug and abandonment (P&A) cost and carbon emissions. This paper will describe a novel logging technology, allowing barrier evaluation of two strings simultaneously without the need to remove the inner string. The dual-string barrier evaluation technology is based on combining advanced ultrasonic multimodality physics with a multimodal deep-probing array sonic measurement providing the capability to map the axial and azimuthal material coverage in the first and second annuli simultaneously. The technology is applicable to evaluate tubing-casing dual-string or casing-casing dual-string environments. Based on the new technology, operators are no longer required to remove the inner string to evaluate the outer string. This approach revolutionizes conventional operations by reducing P&A rig days to minimize costs and overall carbon emissions. Furthermore, when proactively performing dual-string barrier evaluation offline or rigless in a number of wells marked for P&A, operators can use the log data to optimize future rig-based operations, minimize contingencies, and possibly prioritize the rig schedule for specific wells only. This paper discusses an offshore case study where the technology was used in two wells in the southern North Sea during the P&A phase. The measurements and observations with dual-string logging technology will be presented in addition to a validation exercise after pulling the inner string. These dual-string log measurements were subsequently used to streamline the abandonment program in realtime resulting in minimized rig time and scope, subsequently reducing overall carbon emissions. Even though the case study covers wells from a P&A operation, the dual-string technology is equally useful in other well scenarios such as sidetracks or even monitoring barrier integrity in production wells in long-term time-lapse well integrity monitoring. The technology can evaluate different types of barrier material such as cement or formation (shale/salt) squeeze or barite sag in both the first and second strings. Formation squeeze from specific North Sea shale (Williams et al. 2009) or salt members has been tested to act as a competent barrier.
在井的生命周期结束后放弃井，需要跨多个井串进行屏障评估操作。传统的阻隔性评价方法需要通过内套管的切割和拉拔或分段磨铣来暴露外部套管，以便对外部套管进行测井，以验证阻隔性密封。切割和拉拔以及随后的内套管/油管回收或段铣作业成本高，耗时长，通常持续数天，从而增加了封堵和弃井(P&A)的总成本和碳排放。本文将介绍一种新的测井技术，该技术可以同时对两根管柱进行屏障评估，而无需移除内部管柱。双管柱屏障评估技术基于先进的超声多模态物理与多模态深度探测阵列声波测量相结合，能够同时绘制第一环空和第二环空的轴向和方位物质覆盖范围。该技术适用于评价油管-套管双管柱或套管-套管双管柱环境。基于新技术，作业者不再需要移除内管柱来评估外管柱。该方法通过减少封堵弃井作业日数，将成本和总碳排放量降至最低，彻底改变了传统作业方式。此外，当在一些标记为封堵弃井的井中进行离线或无钻机的双管柱屏障评估时，作业者可以利用测井数据优化未来的钻机作业，最大限度地减少意外事故，并可能仅针对特定井优先考虑钻机计划。本文讨论了一个海上案例研究，该技术在北海南部的两口井的P&A阶段被应用。此外，还将介绍双管柱测井技术的测量结果和观察结果，以及拉入内管柱后的验证练习。随后，这些双管柱测井测量结果用于实时简化弃井程序，从而最大限度地减少了钻机时间和范围，从而减少了总体碳排放。尽管案例研究涵盖了弃井作业，但双管柱技术在其他井况中同样有用，例如侧钻，甚至在生产井的长期延时完整性监测中监测屏障完整性。该技术可以评估一、二管柱中不同类型的阻隔材料，如水泥或地层(页岩/盐)挤压或重晶石凹陷。经过测试，北海特定页岩(Williams et al. 2009)或盐层的地层挤压可以作为有效的屏障。
{"title":"Dual-String Barrier Evaluation Innovative Technology for Efficient P&A Operation Impacting CO2 Emissions","authors":"Alhadi Zahmuwl, Kamaljeet Singh, E. Wielemaker, S. Bose, S. Zeroug, Ali Assad, R. Loov, Gulnara Ishberdina, L. Martini","doi":"10.2523/iptc-22925-ea","DOIUrl":"https://doi.org/10.2523/iptc-22925-ea","url":null,"abstract":"\u0000 Abandoning a well after it reaches the end of its life cycle requires a barrier evaluation operation across multiple strings. The traditional method for barrier evaluation requires exposing the outer casing by a cut and pull or section mill of the inner casing so that the outer casing can be logged, to verify the barrier seal. The cut and pull and subsequent inner casing/tubing recovery or section milling operations are costly and time consuming, often lasting for several days, thus increasing the overall plug and abandonment (P&A) cost and carbon emissions. This paper will describe a novel logging technology, allowing barrier evaluation of two strings simultaneously without the need to remove the inner string. The dual-string barrier evaluation technology is based on combining advanced ultrasonic multimodality physics with a multimodal deep-probing array sonic measurement providing the capability to map the axial and azimuthal material coverage in the first and second annuli simultaneously. The technology is applicable to evaluate tubing-casing dual-string or casing-casing dual-string environments.\u0000 Based on the new technology, operators are no longer required to remove the inner string to evaluate the outer string. This approach revolutionizes conventional operations by reducing P&A rig days to minimize costs and overall carbon emissions. Furthermore, when proactively performing dual-string barrier evaluation offline or rigless in a number of wells marked for P&A, operators can use the log data to optimize future rig-based operations, minimize contingencies, and possibly prioritize the rig schedule for specific wells only.\u0000 This paper discusses an offshore case study where the technology was used in two wells in the southern North Sea during the P&A phase. The measurements and observations with dual-string logging technology will be presented in addition to a validation exercise after pulling the inner string. These dual-string log measurements were subsequently used to streamline the abandonment program in realtime resulting in minimized rig time and scope, subsequently reducing overall carbon emissions.\u0000 Even though the case study covers wells from a P&A operation, the dual-string technology is equally useful in other well scenarios such as sidetracks or even monitoring barrier integrity in production wells in long-term time-lapse well integrity monitoring.\u0000 The technology can evaluate different types of barrier material such as cement or formation (shale/salt) squeeze or barite sag in both the first and second strings. Formation squeeze from specific North Sea shale (Williams et al. 2009) or salt members has been tested to act as a competent barrier.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 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":"130310972","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. Sayed, A. Sabaa, A. Samir, Mohamed Mokhtar, A. Medhat, A. El-Wakil
Conventionally, the transition from completion to production often requires the well to be killed immediately after perforation is completed, thus exposing the formation to potentially damaging killing fluid. To obtain a perforation tunnel with maximum productivity, this transition requires an optimal clean-up and removal of the perforation damages. Underbalance perforation through Tubing Conveyed Perforating (TCP) system is one of the best practices to ensure less damage to the perforation tunnels (perforating skin) leading to increased well productivity. However, it is very challenging in cases of completions with Electrical Submersible Pump's (ESP) to maintain productivity with undamaged reservoir by preventing any contact between reservoir and completion fluid and achieve the above simultaneously with safe well control during ESP deployment. Otherwise, the alternative solution is to run TCP string in single run then kill the well after perforation in order to install the ESP completion. As a result of the increasing emphasis on reducing operating costs, maximizing well productivity, and minimizing wellbore clean-up time, an integrated solution was designed and successfully implemented for perforating artificially lifted wells in static underbalanced condition and installing ESP completion in single run without killing the well. It combines the use of TCP system equipped with automatic release gun hanger. TCP gun string has been set by Electric Line against the required intervals, then the ESP has been separately installed and the guns has been activated through an electronic firing head for a shoot-and-drop operation. The static underbalance condition has been created by the ESP thanks to the programmed delayed firing time. After this operation, the well has been directly lined up to production flowline with minimal wellbore clean-up time. The combination of static underbalanced perforation with deep penetration charges which is able to bypass invasion zone, can create a clean perforation tunnel, and significantly reduce the post-perforating damage by killing fluid, and finally maximize the well productivity. Despite the challenging reservoir conditions (Depth= 16,500 FT, Pressure=6250 Psi, Temperature= 285 deg. F, Porosity = 8%), the Productivity Index (PI) of the wells were three times compared to the offset wells. Five jobs have been performed by Agiba Petroleum Company, one of the main operators in Western Desert of Egypt, employing this combined TCP-ESP technique which has resulted in significant savings in rig time and increased operating efficiency. This paper summarizes the practical experiences gained during the development and deployment of this integrated technique, in addition to an evaluation of the impact compared to the conventional perforation techniques through ESP downhole sensor data and well modelling.
{"title":"Effective Utilisation of Underbalanced Perforation with Electrical Submersible Pump's Boost Oil Production of Mature Oil Field in Western Desert of Egypt: Case Study","authors":"M. Sayed, A. Sabaa, A. Samir, Mohamed Mokhtar, A. Medhat, A. El-Wakil","doi":"10.2523/iptc-22793-ea","DOIUrl":"https://doi.org/10.2523/iptc-22793-ea","url":null,"abstract":"\u0000 Conventionally, the transition from completion to production often requires the well to be killed immediately after perforation is completed, thus exposing the formation to potentially damaging killing fluid. To obtain a perforation tunnel with maximum productivity, this transition requires an optimal clean-up and removal of the perforation damages.\u0000 Underbalance perforation through Tubing Conveyed Perforating (TCP) system is one of the best practices to ensure less damage to the perforation tunnels (perforating skin) leading to increased well productivity. However, it is very challenging in cases of completions with Electrical Submersible Pump's (ESP) to maintain productivity with undamaged reservoir by preventing any contact between reservoir and completion fluid and achieve the above simultaneously with safe well control during ESP deployment. Otherwise, the alternative solution is to run TCP string in single run then kill the well after perforation in order to install the ESP completion.\u0000 As a result of the increasing emphasis on reducing operating costs, maximizing well productivity, and minimizing wellbore clean-up time, an integrated solution was designed and successfully implemented for perforating artificially lifted wells in static underbalanced condition and installing ESP completion in single run without killing the well. It combines the use of TCP system equipped with automatic release gun hanger. TCP gun string has been set by Electric Line against the required intervals, then the ESP has been separately installed and the guns has been activated through an electronic firing head for a shoot-and-drop operation. The static underbalance condition has been created by the ESP thanks to the programmed delayed firing time. After this operation, the well has been directly lined up to production flowline with minimal wellbore clean-up time. The combination of static underbalanced perforation with deep penetration charges which is able to bypass invasion zone, can create a clean perforation tunnel, and significantly reduce the post-perforating damage by killing fluid, and finally maximize the well productivity. Despite the challenging reservoir conditions (Depth= 16,500 FT, Pressure=6250 Psi, Temperature= 285 deg. F, Porosity = 8%), the Productivity Index (PI) of the wells were three times compared to the offset wells.\u0000 Five jobs have been performed by Agiba Petroleum Company, one of the main operators in Western Desert of Egypt, employing this combined TCP-ESP technique which has resulted in significant savings in rig time and increased operating efficiency. This paper summarizes the practical experiences gained during the development and deployment of this integrated technique, in addition to an evaluation of the impact compared to the conventional perforation techniques through ESP downhole sensor data and well modelling.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 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":"130545271","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}
Boonyakorn Assavanives, Kantkanit Watanakun, Nunthachai Amarutanon, Z. Kodesh, N. Muangsuankwan, Sunisa Watcharasing, K. Sinthavarayan
Current low-BTU flare tip technologies require a flare gas lower heating value (LHV) of approximately 200 BTU/scf while significant advancement on CO2 removal membrane technology has resulted in an extremely low-BTU waste gases having LHVs around 140 BTU/scf. This requires the extremely lean waste gas to be supplemented with methane to raise its heating value to achieve stable combustion. Not only does the operator lose the benefit of the advanced membrane technology but they also lose product (sellable gas) and have increased green house gas (GHG) emissions at the production site. Consequently, the development of the "Extremely Low-BTU Flare Tip" is beneficial in multiple ways. The Extremely Low-BTU Flare Tip development project was launched as a joint research and development project between PTTEP and John Zink Hamworthy Combustion (JZHC). The innovative design is based on theories behind low heating value gas combustion and improves upon existing low-BTU flare technology. The goal was to obtain flame stability and safe operation in offshore oil and gas production environments at LHVs significantly lower than 200 BTU/scf. This project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize the performance against completeness of combustion criteria. The design was studied through computational fluid dynamics (CFD) simulation and prototype testing to develop the operating envelope of the Extremely Low-BTU Flare Tip. The design of the tip integrates John Zink's existing technology with additional components i.e. spokes and top hat. CFD simulation was performed to observe the fluid behaviors, including temperature, velocity, and unburned hydrocarbon; allowing modification of the design prior to the fabrication of the prototype. The final design has been proven by a series of prototype tests to reinforce the level of confidence in its performance and mechanical integrity. The test results show that the Extremely Low BTU Flare Tip has the capability to combust flare gases with an LHV as low as 110 Btu/scf which is a significant improvement over existing flare tip technology. The benefit of this technology is estimated to be between 10-31 MMUSD per year per platform, depending on the lowest achieved heating value. The success of the Extremely Low BTU flare tip development project provides a breakthrough technology which is not limited to brownfield applications but also supports future acquisition and development of Greenfield sites. This Extremely Low BTU flare tip technology will improve the probability of success for greenfield development with a high CO2 reservoir by maximizing reservoir recovery, optimizing overall capital and operational expenditure, and minimizing hydrocarbons flared which has the direct effect of increasing gas sales and decreasing greenhouse gas emissions.
{"title":"Success Story of the Development of Extremely Low-BTU Flare Tip Technology","authors":"Boonyakorn Assavanives, Kantkanit Watanakun, Nunthachai Amarutanon, Z. Kodesh, N. Muangsuankwan, Sunisa Watcharasing, K. Sinthavarayan","doi":"10.2523/iptc-22799-ea","DOIUrl":"https://doi.org/10.2523/iptc-22799-ea","url":null,"abstract":"\u0000 Current low-BTU flare tip technologies require a flare gas lower heating value (LHV) of approximately 200 BTU/scf while significant advancement on CO2 removal membrane technology has resulted in an extremely low-BTU waste gases having LHVs around 140 BTU/scf. This requires the extremely lean waste gas to be supplemented with methane to raise its heating value to achieve stable combustion. Not only does the operator lose the benefit of the advanced membrane technology but they also lose product (sellable gas) and have increased green house gas (GHG) emissions at the production site. Consequently, the development of the \"Extremely Low-BTU Flare Tip\" is beneficial in multiple ways. The Extremely Low-BTU Flare Tip development project was launched as a joint research and development project between PTTEP and John Zink Hamworthy Combustion (JZHC). The innovative design is based on theories behind low heating value gas combustion and improves upon existing low-BTU flare technology. The goal was to obtain flame stability and safe operation in offshore oil and gas production environments at LHVs significantly lower than 200 BTU/scf. This project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize the performance against completeness of combustion criteria. The design was studied through computational fluid dynamics (CFD) simulation and prototype testing to develop the operating envelope of the Extremely Low-BTU Flare Tip. The design of the tip integrates John Zink's existing technology with additional components i.e. spokes and top hat. CFD simulation was performed to observe the fluid behaviors, including temperature, velocity, and unburned hydrocarbon; allowing modification of the design prior to the fabrication of the prototype. The final design has been proven by a series of prototype tests to reinforce the level of confidence in its performance and mechanical integrity. The test results show that the Extremely Low BTU Flare Tip has the capability to combust flare gases with an LHV as low as 110 Btu/scf which is a significant improvement over existing flare tip technology. The benefit of this technology is estimated to be between 10-31 MMUSD per year per platform, depending on the lowest achieved heating value. The success of the Extremely Low BTU flare tip development project provides a breakthrough technology which is not limited to brownfield applications but also supports future acquisition and development of Greenfield sites. This Extremely Low BTU flare tip technology will improve the probability of success for greenfield development with a high CO2 reservoir by maximizing reservoir recovery, optimizing overall capital and operational expenditure, and minimizing hydrocarbons flared which has the direct effect of increasing gas sales and decreasing greenhouse gas emissions.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"124 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":"131994628","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}
S. Nayak, R. Masoudi, A. Tarang Patrick Panting, M. A. B M Diah, Mohd Razeif B Roslan, M. F. B M Amin, Subramania R Iyer, B. V. Aarssen, Sook Fun, Somen Mishra
High concentration of CO2 in various fields of Malay basin, offshore Peninsular Malaysia pose major challenges in monetizing the resources in a sustainable way. Focused study to understand the source, origin and distribution of CO2 is essential to make informed decisions on developing the fields. This paper is part of the basin scale study to address the distribution of CO2 and its risk assessment. Modelling of the petroleum system including CO2 contaminant was adopted to validate the fluid accumulations in the basin with observed results from fields. An Earth Model was built using maps generated from an integrated study of seismic and 65 key wells. The depth to basement and depth to Moho were incorporated from previous gravity modelling study. The CO2 content and isotope data compiled from reports facilitated in building the knowledge on the source, origin, and distribution over the study area. Play segments identified based on tectonic features were used to divide the basin into subset areas for analysis.
{"title":"Insights on the Origin and Distribution of CO2 in Malay Basin, Offshore Peninsular Malaysia: A Petroleum System Modelling approach","authors":"S. Nayak, R. Masoudi, A. Tarang Patrick Panting, M. A. B M Diah, Mohd Razeif B Roslan, M. F. B M Amin, Subramania R Iyer, B. V. Aarssen, Sook Fun, Somen Mishra","doi":"10.2523/iptc-22832-ea","DOIUrl":"https://doi.org/10.2523/iptc-22832-ea","url":null,"abstract":"\u0000 High concentration of CO2 in various fields of Malay basin, offshore Peninsular Malaysia pose major challenges in monetizing the resources in a sustainable way. Focused study to understand the source, origin and distribution of CO2 is essential to make informed decisions on developing the fields. This paper is part of the basin scale study to address the distribution of CO2 and its risk assessment. Modelling of the petroleum system including CO2 contaminant was adopted to validate the fluid accumulations in the basin with observed results from fields. An Earth Model was built using maps generated from an integrated study of seismic and 65 key wells. The depth to basement and depth to Moho were incorporated from previous gravity modelling study. The CO2 content and isotope data compiled from reports facilitated in building the knowledge on the source, origin, and distribution over the study area. Play segments identified based on tectonic features were used to divide the basin into subset areas for analysis.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"18 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":"129705149","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}
G. Nutricato, C. Repetto, R. Brambilla, Luca Dal Forno, D. Santoro, P. Nunzi, L. Martini, R. Eaton, Aureliano Piccolo, R. Zambetti, Jorge Cordero, Martin J. Goya, N. Santi, Erica Gibellini
In a global context aiming to unlock a low carbon future by industry decarbonization, developing the infrastructure for capturing and storing CO2 emissions is a key target of countries, energy companies and regulatory bodies. Injection for geological storage in suitable reservoirs is an advantageous option which presents challenges related to the completion accessories and string exposed to the injected fluid and the thermodynamical loads during injection and the well life. The purpose of this work is to simulate by numerical analysis and full-scale test, the behavior of a gas-tight Metal-to-Metal OCTG premium dope-free connection when subjected to low temperatures and loads generated by the effect of a sudden CO2 high pressure drop during injection in depleted reservoirs. Extreme temperature drop down caused by the Joule-Thompson (J-T) effect between injection conditions (P-T) inside the tubular and those in the annulus, may expose tubing connections to a thermal shock reaching a temperature near the theoretical figure of -78.5°C. This temperature drop assumed as worst-case scenario is also explored. The analysis is performed considering estimated loads for a CO2 injection case study. The numerical analysis and full-scale test performed confirm the structural and sealability performance of the connection is not affected by the exposure to such low temperatures. Additionally, transient thermal loads, with a drop of approximately 100°C, appears to be not critical for the metal-to-metal dope-free seal integrity and also not affecting the structural integrity of the connection. The challenges setting up of a prototype testing frame, simulating the cooling by thermal shock, lead to a methodology for assessing CCS projects premium connection able to define a robust testing protocol for cryogenic temperatures. The numerical and full-scale results collected on the tested connection size, together with the ones previously tested, allow extrapolation to near sizes of the same premium thread family. The results achieved by testing a premium connection which has been subjected to a thermal shock approaching -78.5°C represent a forefront in the industry, demonstrating the reliability of the product not only in operative conditions during CO2 injection, but also after an extreme event, assessing performance for the CCUS storage projects.
{"title":"Qualification Tests of OCTG Premium Connection under Cryogenic conditions for CCS projects","authors":"G. Nutricato, C. Repetto, R. Brambilla, Luca Dal Forno, D. Santoro, P. Nunzi, L. Martini, R. Eaton, Aureliano Piccolo, R. Zambetti, Jorge Cordero, Martin J. Goya, N. Santi, Erica Gibellini","doi":"10.2523/iptc-22932-ms","DOIUrl":"https://doi.org/10.2523/iptc-22932-ms","url":null,"abstract":"\u0000 In a global context aiming to unlock a low carbon future by industry decarbonization, developing the infrastructure for capturing and storing CO2 emissions is a key target of countries, energy companies and regulatory bodies. Injection for geological storage in suitable reservoirs is an advantageous option which presents challenges related to the completion accessories and string exposed to the injected fluid and the thermodynamical loads during injection and the well life.\u0000 The purpose of this work is to simulate by numerical analysis and full-scale test, the behavior of a gas-tight Metal-to-Metal OCTG premium dope-free connection when subjected to low temperatures and loads generated by the effect of a sudden CO2 high pressure drop during injection in depleted reservoirs. Extreme temperature drop down caused by the Joule-Thompson (J-T) effect between injection conditions (P-T) inside the tubular and those in the annulus, may expose tubing connections to a thermal shock reaching a temperature near the theoretical figure of -78.5°C. This temperature drop assumed as worst-case scenario is also explored. The analysis is performed considering estimated loads for a CO2 injection case study.\u0000 The numerical analysis and full-scale test performed confirm the structural and sealability performance of the connection is not affected by the exposure to such low temperatures. Additionally, transient thermal loads, with a drop of approximately 100°C, appears to be not critical for the metal-to-metal dope-free seal integrity and also not affecting the structural integrity of the connection. The challenges setting up of a prototype testing frame, simulating the cooling by thermal shock, lead to a methodology for assessing CCS projects premium connection able to define a robust testing protocol for cryogenic temperatures. The numerical and full-scale results collected on the tested connection size, together with the ones previously tested, allow extrapolation to near sizes of the same premium thread family.\u0000 The results achieved by testing a premium connection which has been subjected to a thermal shock approaching -78.5°C represent a forefront in the industry, demonstrating the reliability of the product not only in operative conditions during CO2 injection, but also after an extreme event, assessing performance for the CCUS storage projects.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"73 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":"126718037","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}
Hong Chean Lim, A. Leong, Y. Azizan, Khairul Yusoff, D. Sabri, Ziwei Hu, Rudzaifi Adizamri
An offshore horizontal oil well was identified as having multiple tubing leaks and depleting reservoir pressure. Intervention was required to reinstate the well and optimize the gas lift system performance to maximize oil recovery. Various challenges were identified in the project design stage due to the horizontal well trajectory and its potential to cause debris obstructions combined with the absence of any capability to monitor downhole parameters. Software simulations were performed to determine the downhole reach limitations of the rigid tool string to ensure that the deepest Gas Lift Valve (GLV) could be successfully deployed to the target depth under live well conditions. The viability of safely deploying such a long Bottom Hole Assembly (BHA) from a limited deck space with a short riser height also needed to be resolved. To accomplish this while maintaining a double barrier on a live well without setting a deep plug and killing the well required detailed planning. A specific space out of the Coiled Tubing (CT) Pressure Control Equipment (PCE) was tailored to enable the simultaneous holding of a 350 meters long gas lift string while also allowing make-up of the packer assembly on surface. Due to the completion design not containing a suitable profile for depth reference with a conventional mechanical locator tool, the Real-Time (RT) catenary CT system was selected as an ideal method of achieving reliable depth correlation. The catenary CT system, equipped with a BHA containing various RT sensors such as pressure, temperature, compression, tension, inclination, Casing Collar Locator (CCL), Gamma-Ray (GR), and torque, was critical in monitoring the downhole parameters in this challenging trajectory to allow decision making and confirmation during the packer setting process. Despite the complexity of job design, preparation, and operational planning with challenges involving pumping, flowback, and the CT package set up in an offshore environment, this customized solution successfully deployed 350 meters of GLV deepening string with precisely set straddle packers to isolate the leak points without any issues. The completion of this project successfully reinstated significant production following a prolonged shut-in period, and gas lift performance was optimized for maximum oil recovery from the considerable remaining oil reserves in the reservoir. This project marked the first successful deployment of a thru-tubing GLV deepening system on a horizontal well for the asset operator. The catenary CT system was an effective solution that managed to safely achieve all of the objectives while overcoming all the challenges faced throughout the project.
{"title":"A Customised Solution Using Catenary Coiled Tubing to Deploy a Gas Lift Valve Deepening System With Straddle Packers For a Challenging Horizontal Well Offshore Brunei","authors":"Hong Chean Lim, A. Leong, Y. Azizan, Khairul Yusoff, D. Sabri, Ziwei Hu, Rudzaifi Adizamri","doi":"10.2523/iptc-22820-ea","DOIUrl":"https://doi.org/10.2523/iptc-22820-ea","url":null,"abstract":"\u0000 An offshore horizontal oil well was identified as having multiple tubing leaks and depleting reservoir pressure. Intervention was required to reinstate the well and optimize the gas lift system performance to maximize oil recovery.\u0000 Various challenges were identified in the project design stage due to the horizontal well trajectory and its potential to cause debris obstructions combined with the absence of any capability to monitor downhole parameters. Software simulations were performed to determine the downhole reach limitations of the rigid tool string to ensure that the deepest Gas Lift Valve (GLV) could be successfully deployed to the target depth under live well conditions. The viability of safely deploying such a long Bottom Hole Assembly (BHA) from a limited deck space with a short riser height also needed to be resolved. To accomplish this while maintaining a double barrier on a live well without setting a deep plug and killing the well required detailed planning. A specific space out of the Coiled Tubing (CT) Pressure Control Equipment (PCE) was tailored to enable the simultaneous holding of a 350 meters long gas lift string while also allowing make-up of the packer assembly on surface. Due to the completion design not containing a suitable profile for depth reference with a conventional mechanical locator tool, the Real-Time (RT) catenary CT system was selected as an ideal method of achieving reliable depth correlation.\u0000 The catenary CT system, equipped with a BHA containing various RT sensors such as pressure, temperature, compression, tension, inclination, Casing Collar Locator (CCL), Gamma-Ray (GR), and torque, was critical in monitoring the downhole parameters in this challenging trajectory to allow decision making and confirmation during the packer setting process. Despite the complexity of job design, preparation, and operational planning with challenges involving pumping, flowback, and the CT package set up in an offshore environment, this customized solution successfully deployed 350 meters of GLV deepening string with precisely set straddle packers to isolate the leak points without any issues. The completion of this project successfully reinstated significant production following a prolonged shut-in period, and gas lift performance was optimized for maximum oil recovery from the considerable remaining oil reserves in the reservoir.\u0000 This project marked the first successful deployment of a thru-tubing GLV deepening system on a horizontal well for the asset operator. The catenary CT system was an effective solution that managed to safely achieve all of the objectives while overcoming all the challenges faced throughout the project.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"18 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":"126068625","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}
Aldia Syamsudhuha, Ahmed El Nakhlawi, Faizan Ahmed Siddiqi, F. Marin, Saleh Mohammed Al Marri, E. Brahmanto, Sarvodaya Bansal
In a deep gas wells drilling project, due to surface location limitations, predetermined target, and completion requirements, an S shape well profile is required. The well type is one of the most challenging due to the extended tangent section, increasing the risk of differential sticking, hole cleaning, extended reaming while tripping, and losses risk from the fracture-prone formation. An aggressive target at the outmost reservoir boundary is determined, requiring delivery of the furthest step-out S shape well, demanding more advanced technology and rigorous well planning. Comprehensive well planning and strategy, utilizing cutting-edge technology to achieve the furthest step-out S shape well. –Thorough offset wells analysis, identifying best drilling practices for the most critical S shape directional section.–Modified S shape well design, dividing two directional sections to enable reaching desired reservoir target.–Latest generation of RSS technology with a more robust system and improved tool reliability, enabling the achievement of required DLS in high drilling dynamic conditions.–Optimized BHA design, improved drilling fluid design, and LCM strategy, enabling the achievement of maximum drilling parameters while minimizing differential sticking and losses risk.–Specific casing and light cementing design strategy in the extensive S shape section allowing the casing to reach the bottom smoothly and avoid losses risk while cementing due to higher ECD. High drilling performance was achieved within the S shape well type in the field with no downhole tool failure nor drilling complexity and meeting desired well trajectory. High losses risk in the section and differential sticking was avoided, ensuring close adherence to drilling fluid parameters with bridge and seal strategy while drilling. The determined reservoir target was successfully reached with a total horizontal displacement of 3,140 ft (~1 km), resulting in the longest step-out S shape well in the deep gas well project. No wiper trip was required prior to running casing following best drilling practices and drilling fluid design and strategy prior to POOH the BHA. The casing string was able to run smoothly in the field's longest open hole section, with less than maximum rig hoisting capacity, following low drag friction factor to the casing point. The cementing job was performed using a real-time top of cement identifier and was further performed successfully without inducing any losses using a light slurry strategy and met the objective to seal off the reservoir formation. The novel holistic strategy encompasses cutting-edge technology utilization, Innovative well construction design, optimized BHA and drilling strategy, drilling fluid strategy, and specific measures in the casing and cementing design and execution, resulting in successfully delivering the longest step-out S Shape well in a deep gas drilling project. Collaboration from a team consisting of multi-technical expertis
{"title":"Reaching Beyond the Limit, the Furthest Step Out S Shape Wells in Deep Gas Well Project","authors":"Aldia Syamsudhuha, Ahmed El Nakhlawi, Faizan Ahmed Siddiqi, F. Marin, Saleh Mohammed Al Marri, E. Brahmanto, Sarvodaya Bansal","doi":"10.2523/iptc-22787-ms","DOIUrl":"https://doi.org/10.2523/iptc-22787-ms","url":null,"abstract":"\u0000 In a deep gas wells drilling project, due to surface location limitations, predetermined target, and completion requirements, an S shape well profile is required. The well type is one of the most challenging due to the extended tangent section, increasing the risk of differential sticking, hole cleaning, extended reaming while tripping, and losses risk from the fracture-prone formation. An aggressive target at the outmost reservoir boundary is determined, requiring delivery of the furthest step-out S shape well, demanding more advanced technology and rigorous well planning.\u0000 Comprehensive well planning and strategy, utilizing cutting-edge technology to achieve the furthest step-out S shape well. –Thorough offset wells analysis, identifying best drilling practices for the most critical S shape directional section.–Modified S shape well design, dividing two directional sections to enable reaching desired reservoir target.–Latest generation of RSS technology with a more robust system and improved tool reliability, enabling the achievement of required DLS in high drilling dynamic conditions.–Optimized BHA design, improved drilling fluid design, and LCM strategy, enabling the achievement of maximum drilling parameters while minimizing differential sticking and losses risk.–Specific casing and light cementing design strategy in the extensive S shape section allowing the casing to reach the bottom smoothly and avoid losses risk while cementing due to higher ECD.\u0000 High drilling performance was achieved within the S shape well type in the field with no downhole tool failure nor drilling complexity and meeting desired well trajectory. High losses risk in the section and differential sticking was avoided, ensuring close adherence to drilling fluid parameters with bridge and seal strategy while drilling. The determined reservoir target was successfully reached with a total horizontal displacement of 3,140 ft (~1 km), resulting in the longest step-out S shape well in the deep gas well project.\u0000 No wiper trip was required prior to running casing following best drilling practices and drilling fluid design and strategy prior to POOH the BHA. The casing string was able to run smoothly in the field's longest open hole section, with less than maximum rig hoisting capacity, following low drag friction factor to the casing point. The cementing job was performed using a real-time top of cement identifier and was further performed successfully without inducing any losses using a light slurry strategy and met the objective to seal off the reservoir formation.\u0000 The novel holistic strategy encompasses cutting-edge technology utilization, Innovative well construction design, optimized BHA and drilling strategy, drilling fluid strategy, and specific measures in the casing and cementing design and execution, resulting in successfully delivering the longest step-out S Shape well in a deep gas drilling project. Collaboration from a team consisting of multi-technical expertis","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"36 ","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113990851","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. Das, S. Nayak, T. Kurniawan, Azwari Huslan B Mohd
This article briefly discusses the workflow through which a gas discovery was made within the Late Miocene interval (Lower and Upper Stage IVD) from the structurally down-flank of a three-way fault closure, where previously an unsuccessful campaign was carried out in the structurally higher location. The causes for the failure were attributed to reservoir absence and trap incompetency. An attempt was made to understand the causes of facies variations and their limits through an integrated sequence stratigraphic approach. This model was further concretized through post-stack attributes where the limits of the seismic facies were prominent. A quantitative interpretation (QI) study coupled with forward modelling helped de-risk the reservoir presence and fluid types. Rock physics modelling work, including shear log prediction, rock property modelling, depth -trend analysis, followed by simultaneous inversion and sand probability volume generation, reveals that the deeper part of Upper Stage IVD and Lower Stage IVD intervals were shale-out and pinch-out, respectively, for the earlier campaign. Likewise, sand-dominated facies are likely at the down-dip for both intervals with an effective lateral seal up-dip (due to facies change and pinch out). Finally, this integration led to a hydrocarbon discovery in a previously written-off fault block and proved a potential stratigraphic trap presence in this area. The well encountered 50 m of net gas-bearing sand within both intervals. This approach could further facilitate exploring stratigraphic play (s) in a similar geological setup.
{"title":"Deliberate Search for Stratigraphic Traps: A Success Story from Sabah Offshore","authors":"P. Das, S. Nayak, T. Kurniawan, Azwari Huslan B Mohd","doi":"10.2523/iptc-22846-ea","DOIUrl":"https://doi.org/10.2523/iptc-22846-ea","url":null,"abstract":"\u0000 \u0000 \u0000 \u0000 This article briefly discusses the workflow through which a gas discovery was made within the Late Miocene interval (Lower and Upper Stage IVD) from the structurally down-flank of a three-way fault closure, where previously an unsuccessful campaign was carried out in the structurally higher location. The causes for the failure were attributed to reservoir absence and trap incompetency. An attempt was made to understand the causes of facies variations and their limits through an integrated sequence stratigraphic approach. This model was further concretized through post-stack attributes where the limits of the seismic facies were prominent. A quantitative interpretation (QI) study coupled with forward modelling helped de-risk the reservoir presence and fluid types. Rock physics modelling work, including shear log prediction, rock property modelling, depth -trend analysis, followed by simultaneous inversion and sand probability volume generation, reveals that the deeper part of Upper Stage IVD and Lower Stage IVD intervals were shale-out and pinch-out, respectively, for the earlier campaign. Likewise, sand-dominated facies are likely at the down-dip for both intervals with an effective lateral seal up-dip (due to facies change and pinch out). Finally, this integration led to a hydrocarbon discovery in a previously written-off fault block and proved a potential stratigraphic trap presence in this area. The well encountered 50 m of net gas-bearing sand within both intervals. This approach could further facilitate exploring stratigraphic play (s) in a similar geological setup.\u0000 \u0000","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"83 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":"132837904","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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