Chaiyos Thurawat, W. Teeratananon, T. Ampaiwan, Raweewan Carter, W. Phaophongklai, Pojana Vimolsubsin, R. Watcharanantakul, Haifeng Wang, Trinant Foongthongcharoen, K. Alang
The recent development drilling campaign at Mubadala Petroleum's offshore Nong Yao field faced many challenges, one of which is the complexity of the reservoir which consists of mixed sand-shale sequencies with thin sand lobes of varying thicknesses. To tackle these challenges and to maximize recovery, Mubadala Petroleum planned four horizontal wells for this campaign. However, the conventional methods of geosteering have limitations. For instance, the distance-to-boundary mapping tool typically does not provide large enough depth-of-investigation for the operator to see through the interbedded shale layer to identify the multiple target sand lobes, which could pose limits on the production optimization and ultimately on the final recovery rate. Fortunately, a new technology emerged at the start of the campaign with a potential for a much larger depth of investigation and a better mapping resolution. This multilayer mapping-while-drilling tool was an extension of the previous tool with additional sensors that could read deeper into the formation. Coupled with a new advanced automatic inversion process which utilizes powerful Cloud computing, the subsurface formation resistivity profiles around the wellbore could be mapped clearly up to 25 ft away from the tool, while providing a multilayer mapping with up to 8-layer mapping capability. This new technology was evaluated and applied in two wells in this campaign to resolve the above-mentioned challenges. The result was a resounding success for the Mubadala led drilling team. In this paper, the authors explain the technology, the process of evaluating and applying it to operation, and the results from applying it. This was the first time that this technology was used in Thailand and this case study summarizes a successful outcome. The mapping results from the tool will also be used to update the reservoir model during the post-job phase and provide improvements of the overall reservoir characterization of the field.
{"title":"High-Resolution Remote Mapping of Thin Sand Lobes with Novel Multilayer Mapping-While-Drilling Tool: A Case Study from Nong Yao Field Offshore Thailand","authors":"Chaiyos Thurawat, W. Teeratananon, T. Ampaiwan, Raweewan Carter, W. Phaophongklai, Pojana Vimolsubsin, R. Watcharanantakul, Haifeng Wang, Trinant Foongthongcharoen, K. Alang","doi":"10.2118/209863-ms","DOIUrl":"https://doi.org/10.2118/209863-ms","url":null,"abstract":"\u0000 The recent development drilling campaign at Mubadala Petroleum's offshore Nong Yao field faced many challenges, one of which is the complexity of the reservoir which consists of mixed sand-shale sequencies with thin sand lobes of varying thicknesses. To tackle these challenges and to maximize recovery, Mubadala Petroleum planned four horizontal wells for this campaign. However, the conventional methods of geosteering have limitations. For instance, the distance-to-boundary mapping tool typically does not provide large enough depth-of-investigation for the operator to see through the interbedded shale layer to identify the multiple target sand lobes, which could pose limits on the production optimization and ultimately on the final recovery rate.\u0000 Fortunately, a new technology emerged at the start of the campaign with a potential for a much larger depth of investigation and a better mapping resolution. This multilayer mapping-while-drilling tool was an extension of the previous tool with additional sensors that could read deeper into the formation. Coupled with a new advanced automatic inversion process which utilizes powerful Cloud computing, the subsurface formation resistivity profiles around the wellbore could be mapped clearly up to 25 ft away from the tool, while providing a multilayer mapping with up to 8-layer mapping capability.\u0000 This new technology was evaluated and applied in two wells in this campaign to resolve the above-mentioned challenges. The result was a resounding success for the Mubadala led drilling team. In this paper, the authors explain the technology, the process of evaluating and applying it to operation, and the results from applying it.\u0000 This was the first time that this technology was used in Thailand and this case study summarizes a successful outcome. The mapping results from the tool will also be used to update the reservoir model during the post-job phase and provide improvements of the overall reservoir characterization of the field.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133315165","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}
Fei Zhou, H. Fan, Baoping Lu, Hongbao Zhang, Yuhan Liu, Xingang Tao, Kankan Bai
Rate of Penetration (ROP) prediction is the theoretical core of drilling tool selection and drilling parameter optimization. In recent years, researchers have proposed a variety of ROP prediction models, which can usually be divided into the following two types: traditional empirical and theoretical formula methods, and methods based on data-driven or machine learning techniques. However, the above methods only consider the engineering or formation parameters corresponding to the depth to be drilled, while ignoring the force and motion state of the drilling tool of thousands of meters in the irregular wellbore, which makes it difficult to improve the prediction accuracy of the ROP and can't meet the requirements of drilling parameter control in the era of intelligent drilling. This paper proposes a DNN-TCN composite neural network that can handle both non-sequential features and sequential features. The DNN-TCN model not only considers engineering and geological parameters (non-sequential features: weight on bit, revolutions per minute, gamma ray, etc.), but also considers the force and motion states of drilling tools in the wellbore (sequential features: deviation angle, azimuth angle, dog leg, borehole size, diameter of drilling tool, etc.). The first branch of the DNN-TCN model is DNN, which is used to process non-sequential features; the second branch is TCN, which is used to process sequence features. Using a fully connected neural network to fuse the output layers of branch one and branch two, a new network structure can be obtained—DNN-TCN composite neural network. This paper collects data from 50 wells in a specific field to train and test the model. Root mean squared error (RMSE) and a self-definition indicator which named average accuracy (AA) are adopted to evaluate models performance. The results show that the DNN-TCN composite neural network has higher prediction accuracy than traditional theoretical/empirical models and others machine learning models. In addition, because the DNN-TCN model considers the force and motion state of the drilling tool in the wellbore, the accuracy of the ROP prediction for directional wells is greatly improved, which can't be achieved by other models. That is to say, the DNN-TCN model can have better performance, and the model has good universality. The DNN-TCN model combines the following two capabilities: 1, The powerful nonlinear mapping ability of Deep Neural Networks (DNN) in dealing with high-dimensional complex problems; and 2, The long-term memory ability of Temporal Convolutional Neural Network (TCN) in dealing with sequence problems. The model considers the force and motion state of the drilling tool in the wellbore, and effectively improves the prediction accuracy of the ROP. It is an important basis for drilling tool optimization, drilling parameter design and real-time optimization, and helps to improve the intelligence level and construction efficiency of drilling engineering.
{"title":"Application of DNN-TCN Composite Neural Network in Rate of Penetration Prediction","authors":"Fei Zhou, H. Fan, Baoping Lu, Hongbao Zhang, Yuhan Liu, Xingang Tao, Kankan Bai","doi":"10.2118/209886-ms","DOIUrl":"https://doi.org/10.2118/209886-ms","url":null,"abstract":"\u0000 Rate of Penetration (ROP) prediction is the theoretical core of drilling tool selection and drilling parameter optimization. In recent years, researchers have proposed a variety of ROP prediction models, which can usually be divided into the following two types: traditional empirical and theoretical formula methods, and methods based on data-driven or machine learning techniques. However, the above methods only consider the engineering or formation parameters corresponding to the depth to be drilled, while ignoring the force and motion state of the drilling tool of thousands of meters in the irregular wellbore, which makes it difficult to improve the prediction accuracy of the ROP and can't meet the requirements of drilling parameter control in the era of intelligent drilling.\u0000 This paper proposes a DNN-TCN composite neural network that can handle both non-sequential features and sequential features. The DNN-TCN model not only considers engineering and geological parameters (non-sequential features: weight on bit, revolutions per minute, gamma ray, etc.), but also considers the force and motion states of drilling tools in the wellbore (sequential features: deviation angle, azimuth angle, dog leg, borehole size, diameter of drilling tool, etc.). The first branch of the DNN-TCN model is DNN, which is used to process non-sequential features; the second branch is TCN, which is used to process sequence features. Using a fully connected neural network to fuse the output layers of branch one and branch two, a new network structure can be obtained—DNN-TCN composite neural network.\u0000 This paper collects data from 50 wells in a specific field to train and test the model. Root mean squared error (RMSE) and a self-definition indicator which named average accuracy (AA) are adopted to evaluate models performance. The results show that the DNN-TCN composite neural network has higher prediction accuracy than traditional theoretical/empirical models and others machine learning models. In addition, because the DNN-TCN model considers the force and motion state of the drilling tool in the wellbore, the accuracy of the ROP prediction for directional wells is greatly improved, which can't be achieved by other models. That is to say, the DNN-TCN model can have better performance, and the model has good universality.\u0000 The DNN-TCN model combines the following two capabilities: 1, The powerful nonlinear mapping ability of Deep Neural Networks (DNN) in dealing with high-dimensional complex problems; and 2, The long-term memory ability of Temporal Convolutional Neural Network (TCN) in dealing with sequence problems. The model considers the force and motion state of the drilling tool in the wellbore, and effectively improves the prediction accuracy of the ROP. It is an important basis for drilling tool optimization, drilling parameter design and real-time optimization, and helps to improve the intelligence level and construction efficiency of drilling engineering.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124193534","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}
V. Pinprayong, Myo Htet, M. A. Seleman, Annie Lim, Kevin Riaz
Wireline pipe recovery operation on a floater type offshore rig such as a semi-submersible or drillship can be challenging when heave motion affects the wireline cable, depth accuracy, cable tension, rig-up equipment positions, and well control. The heave motion compensator (HMC) unit connected on top of the top-drive system (TDS) has a narrow gap that allows a wireline cable to pass through and could cause damage to the wireline cable. Conventional processes in performing pipe recovery operations only permit operations to occur on the open end of the drillpipe while on the rotary table. With a long bailer arm, the cable will have enough clearance to pass through the elevator then enter the TDS body, but this process also prevents the operator from establishing a barrier for well control situations because the top of the drillpipe remains open. The other issue is depth accuracy, where heave motion causes both upward and downward movement on the cable while wireline is being run in hole (RIH) or pulled out of the hole (POOH). The depth shifts due to heaving motion could cause a back-off string shot to be fired off at depth. To overcome these issues, the Smart Sub system—a combination of a special side-entry sub (SES), pad eye sub, and a swivel sub—allows heave motion to be compensated to the top sheave and enables the wireline cable to be positioned in front of the TDS unlike the conventional method where the cable remains in contact with the TDS. The real result of this combination is studied from the pipe recovery operation performed on semi-submersible rig in Myanmar.
{"title":"Combination of Side Entry Sub, Pad Eye Sub, and Swivel Sub Prevents Damage to Wireline Cable and Allows Heave Compensation on a Semi-submersible Rig for Pipe Recovery Operation","authors":"V. Pinprayong, Myo Htet, M. A. Seleman, Annie Lim, Kevin Riaz","doi":"10.2118/209905-ms","DOIUrl":"https://doi.org/10.2118/209905-ms","url":null,"abstract":"\u0000 Wireline pipe recovery operation on a floater type offshore rig such as a semi-submersible or drillship can be challenging when heave motion affects the wireline cable, depth accuracy, cable tension, rig-up equipment positions, and well control. The heave motion compensator (HMC) unit connected on top of the top-drive system (TDS) has a narrow gap that allows a wireline cable to pass through and could cause damage to the wireline cable. Conventional processes in performing pipe recovery operations only permit operations to occur on the open end of the drillpipe while on the rotary table. With a long bailer arm, the cable will have enough clearance to pass through the elevator then enter the TDS body, but this process also prevents the operator from establishing a barrier for well control situations because the top of the drillpipe remains open. The other issue is depth accuracy, where heave motion causes both upward and downward movement on the cable while wireline is being run in hole (RIH) or pulled out of the hole (POOH). The depth shifts due to heaving motion could cause a back-off string shot to be fired off at depth.\u0000 To overcome these issues, the Smart Sub system—a combination of a special side-entry sub (SES), pad eye sub, and a swivel sub—allows heave motion to be compensated to the top sheave and enables the wireline cable to be positioned in front of the TDS unlike the conventional method where the cable remains in contact with the TDS. The real result of this combination is studied from the pipe recovery operation performed on semi-submersible rig in Myanmar.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128926558","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 unconventional oil and gas resources continuously discovered in China are mainly concentrated in the Junggar Basin, Ordos Basin, Sichuan Basin and Songliao Basin. However, the porosity and permeability of its shale reservoirs are extremely low, which brings relatively great difficulties and challenges to the economic development of shale oil reservoir. Long horizontal well section drilling and multi-stage hydraulic fracturing are the key technologies of unconventional resources development. The operations can increase the stimulated volume and ultimately achieve the goal of improving production. In addition, shale reservoirs natural fractures and horizontal bedding are developed, leading to shear slip and tensile failure during the fracturing propagation process. Moreover, the hydraulic fracture is no longer a single symmetrical two-wing fracture, and it is very likely to form a relatively very complex fracture network. This will bring many inconveniences to shale hydraulic fracturing design, fracture monitoring and interpretation, and post-fracturing productivity prediction. Geomechanics is the important influencing parameter that affects the design of hydraulic fracturing. This research is mainly based on the research results of 3D geomechanics to continuously optimize hydraulic fracturing design for horizontal wells. In addition, the implementation of hydraulic fracturing can significantly reduce the seepage resistance of fluids in the formation near the bottom of the well. This will be a very effective mean to increase well production for unconventional resources. Hydraulic fracturing optimization technique fully-coupling 3D geomechanical modeling was applied in the unconventional reservoir in the northeast of Junggar Basin. The shale oil reservoir of Permian Lucaogou formation is one of the main unconventional resources in China. This case study discusses the multi-stages fracturing optimization of horizontal well-A based on the fully coupled 3D Geomechanical modeling. The research result clearly characterizes the stress model variation and reduces the uncertainties in horizontal well-A1 for hydraulic fracturing operation. The uncertainty of the fracture modeling geometry was greatly reduced, and fracture geometry was verified by micro-seismic patterns. The geomechanical modeling helps to optimize the pressure pumping rate, the volume of proppant and fracturing fluids, eventually maximizes the increase of fracture flow conductivity and post-stimulation production.
{"title":"Integrating the Fully Coupled 3D Geomechanical Modeling for Hydraulic Fracturing Optimization of Unconventional Resources","authors":"Leiming Cheng, Ying-wei Wang, Haiyan Zhao, Jiacheng Li, Xiao Liu, Qiyao Liu, Xingning Huang, Thanapol Singjaroen, Piyanuch Kieduppatum","doi":"10.2118/209847-ms","DOIUrl":"https://doi.org/10.2118/209847-ms","url":null,"abstract":"\u0000 The unconventional oil and gas resources continuously discovered in China are mainly concentrated in the Junggar Basin, Ordos Basin, Sichuan Basin and Songliao Basin. However, the porosity and permeability of its shale reservoirs are extremely low, which brings relatively great difficulties and challenges to the economic development of shale oil reservoir. Long horizontal well section drilling and multi-stage hydraulic fracturing are the key technologies of unconventional resources development. The operations can increase the stimulated volume and ultimately achieve the goal of improving production. In addition, shale reservoirs natural fractures and horizontal bedding are developed, leading to shear slip and tensile failure during the fracturing propagation process. Moreover, the hydraulic fracture is no longer a single symmetrical two-wing fracture, and it is very likely to form a relatively very complex fracture network. This will bring many inconveniences to shale hydraulic fracturing design, fracture monitoring and interpretation, and post-fracturing productivity prediction. Geomechanics is the important influencing parameter that affects the design of hydraulic fracturing. This research is mainly based on the research results of 3D geomechanics to continuously optimize hydraulic fracturing design for horizontal wells. In addition, the implementation of hydraulic fracturing can significantly reduce the seepage resistance of fluids in the formation near the bottom of the well. This will be a very effective mean to increase well production for unconventional resources. Hydraulic fracturing optimization technique fully-coupling 3D geomechanical modeling was applied in the unconventional reservoir in the northeast of Junggar Basin. The shale oil reservoir of Permian Lucaogou formation is one of the main unconventional resources in China. This case study discusses the multi-stages fracturing optimization of horizontal well-A based on the fully coupled 3D Geomechanical modeling. The research result clearly characterizes the stress model variation and reduces the uncertainties in horizontal well-A1 for hydraulic fracturing operation. The uncertainty of the fracture modeling geometry was greatly reduced, and fracture geometry was verified by micro-seismic patterns. The geomechanical modeling helps to optimize the pressure pumping rate, the volume of proppant and fracturing fluids, eventually maximizes the increase of fracture flow conductivity and post-stimulation production.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125350228","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 aims to elaborate the strategy for operational and cost efficiency improvement by providing an example of a successful case of rig selection strategy for Hydraulic Fracturing Operation in S1 oil field Thailand. The integrated workflow proposed involves all concerned parties to specify the scope of work, analyze internal and external strengths and weaknesses, evaluate possible scenarios, and identify the procurement strategy. As a case of rig selection for fracturing operation in the heterogeneous sandstone, committing the number of candidates before drilling is impossible. Therefore, the typical criteria for fracturing rig selection consider rig move mobility and flexibility in candidate selection. However, in a proven area, the uncertainty of candidate confirmation is manageable. Reservoir engineers provide the number of candidates in 3 scenarios for sensitivity analysis. SWOT analysis and the market survey reveal the possibility to improve both performance and cost by using a warm-stack skidding rig instead of a truck-mounted rig. The sensitivity analysis by using the historical data of each type, indicates that the number of candidates and rig cost play a significant role in cost saving. As a result of analysis and strategy, the operation performance improvesby 34% (2 months reduction) leading to cost-saving by 1MM USD or 24% of the time-dependent cost.
{"title":"Pragmatic Strategy for Operational and Cost Efficiency Improvement: A Case Study of Rig Selection Strategy for Hydraulic Fracturing Operation in S1 Oil Field Thailand","authors":"Thum Sirirattanachatchawan, Sukrit Kanjanarat, Pavin Pirom, Kanwisa Siriphruek, Anan Tantianon, Apiwat Nadoon, Meth Follett, Chatchai Paramart, Arisara Kukiattikoon","doi":"10.2118/209843-ms","DOIUrl":"https://doi.org/10.2118/209843-ms","url":null,"abstract":"\u0000 This paper aims to elaborate the strategy for operational and cost efficiency improvement by providing an example of a successful case of rig selection strategy for Hydraulic Fracturing Operation in S1 oil field Thailand. The integrated workflow proposed involves all concerned parties to specify the scope of work, analyze internal and external strengths and weaknesses, evaluate possible scenarios, and identify the procurement strategy. As a case of rig selection for fracturing operation in the heterogeneous sandstone, committing the number of candidates before drilling is impossible. Therefore, the typical criteria for fracturing rig selection consider rig move mobility and flexibility in candidate selection. However, in a proven area, the uncertainty of candidate confirmation is manageable. Reservoir engineers provide the number of candidates in 3 scenarios for sensitivity analysis. SWOT analysis and the market survey reveal the possibility to improve both performance and cost by using a warm-stack skidding rig instead of a truck-mounted rig. The sensitivity analysis by using the historical data of each type, indicates that the number of candidates and rig cost play a significant role in cost saving. As a result of analysis and strategy, the operation performance improvesby 34% (2 months reduction) leading to cost-saving by 1MM USD or 24% of the time-dependent cost.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126375752","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}
Wararit Toempromraj, C. Grant, C. Chanpen, Kittipat Wejwittayaklung, Pornchuda Konganuntragul, P. Bandyopadhyay, Noppadon Kosiri, Naruttee Kovitkanit, Prapapor Jantasuwanna, S. Buapha, Pat Kachondham, Wich Huengwattanakul, Teerath Srikijkarn, Matus Pulsawat, Anucha Thippayawarn, Maneenapang Bunnag, Ghazanfar Shahid, Shelagh J. Baines, Christie Usun Ngau, S. Obrien, Shraddha Chattopadhyay, Lim Sook Fun, Reawat Wattanasuwankorn
Interest in CCS project development is accelerating in SE Asia, driven by the need to monetize emission-intensive assets in the region while complying with increasingly ambitious GHG emissions targets. Depleted hydrocarbon fields represent an attractive storage option for early CCS project due the enhanced understanding of the reservoir, its dynamic behavior, and proven storage capability. Re-use of existing infrastructure also presents the potential to reduce both project costs and time to first injection, however, these brownfield sites also carry significant risk to the long-term, safe containment of injected CO2 through risk of leakage via legacy wells. A methodology is presented in this paper to investigate the risk-reward balance of developing a depleted gas field as a storage site in the Gulf of Thailand. A screening process to assess all abandoned, suspended, and active wells is used to identify wells with re-use potential as CO2 injectors or CO2 plume monitoring wells, and those which represent a leakage risk to the project. A set of legacy well risk identifiers is generated for the field based on well construction records, descriptions of current well barriers, well utilization history, and current best practice guidelines. Southeast Asia has significant remaining reserves of oil and gas, and coal, and an active liquefied natural gas (LNG) export industry. The region's energy demand is increasing rapidly and is forecast to continue to grow over the next decades (World Economic Forum, 2019). To date, fossil fuels have supplied nearly 90% of this growth in the demand for energy in the region (IEA, 2021). To meet this growing energy demand, several new gas projects are under development across Southeast Asia, but many of these are associated with high CO2 gas fields where the produced gas contains significant (up to 70% by volume) CO2 (GCCSI, 2020). In Thailand, where nearly 94% of the primary energy is met by fossil fuels (BP Statistical Review, 2022), the energy sector represents the biggest contributor (74% in 2013) to the country's greenhouse gas emissions (GHG; UNFCCC, 2020). However, as per the nationally determined contribution to the United Nations Framework Convention on Climate Change (UNFCCC), Thailand intends to reduce its GHG emissions by at least 20% from projected business as usual levels by the year 2030 (UNFCCC, 2020). Carbon capture and storage (CCS) represents one option to help meet this increased demand in fossil energy while also reducing GHG emissions. An approach which is gaining traction across the region is to utilize the high concentrations of CO2 stripped out of the raw gas streams at gas processing plants and, instead of venting to atmosphere, the CO2 can be compressed, dehydrated, and transported to suitable long-term storage locations. Depleted oil and gas fields form an attractive opportunity for long-term storage of CO2 due to the wealth of both static and dynamic knowledge available from appraisal throu
{"title":"Old Field, New Well: Well Design Challenge for Long-Terms CO2 Storage in a Depleted Field","authors":"Wararit Toempromraj, C. Grant, C. Chanpen, Kittipat Wejwittayaklung, Pornchuda Konganuntragul, P. Bandyopadhyay, Noppadon Kosiri, Naruttee Kovitkanit, Prapapor Jantasuwanna, S. Buapha, Pat Kachondham, Wich Huengwattanakul, Teerath Srikijkarn, Matus Pulsawat, Anucha Thippayawarn, Maneenapang Bunnag, Ghazanfar Shahid, Shelagh J. Baines, Christie Usun Ngau, S. Obrien, Shraddha Chattopadhyay, Lim Sook Fun, Reawat Wattanasuwankorn","doi":"10.2118/209861-ms","DOIUrl":"https://doi.org/10.2118/209861-ms","url":null,"abstract":"\u0000 Interest in CCS project development is accelerating in SE Asia, driven by the need to monetize emission-intensive assets in the region while complying with increasingly ambitious GHG emissions targets. Depleted hydrocarbon fields represent an attractive storage option for early CCS project due the enhanced understanding of the reservoir, its dynamic behavior, and proven storage capability. Re-use of existing infrastructure also presents the potential to reduce both project costs and time to first injection, however, these brownfield sites also carry significant risk to the long-term, safe containment of injected CO2 through risk of leakage via legacy wells. A methodology is presented in this paper to investigate the risk-reward balance of developing a depleted gas field as a storage site in the Gulf of Thailand. A screening process to assess all abandoned, suspended, and active wells is used to identify wells with re-use potential as CO2 injectors or CO2 plume monitoring wells, and those which represent a leakage risk to the project. A set of legacy well risk identifiers is generated for the field based on well construction records, descriptions of current well barriers, well utilization history, and current best practice guidelines.\u0000 Southeast Asia has significant remaining reserves of oil and gas, and coal, and an active liquefied natural gas (LNG) export industry. The region's energy demand is increasing rapidly and is forecast to continue to grow over the next decades (World Economic Forum, 2019). To date, fossil fuels have supplied nearly 90% of this growth in the demand for energy in the region (IEA, 2021). To meet this growing energy demand, several new gas projects are under development across Southeast Asia, but many of these are associated with high CO2 gas fields where the produced gas contains significant (up to 70% by volume) CO2 (GCCSI, 2020). In Thailand, where nearly 94% of the primary energy is met by fossil fuels (BP Statistical Review, 2022), the energy sector represents the biggest contributor (74% in 2013) to the country's greenhouse gas emissions (GHG; UNFCCC, 2020). However, as per the nationally determined contribution to the United Nations Framework Convention on Climate Change (UNFCCC), Thailand intends to reduce its GHG emissions by at least 20% from projected business as usual levels by the year 2030 (UNFCCC, 2020). Carbon capture and storage (CCS) represents one option to help meet this increased demand in fossil energy while also reducing GHG emissions. An approach which is gaining traction across the region is to utilize the high concentrations of CO2 stripped out of the raw gas streams at gas processing plants and, instead of venting to atmosphere, the CO2 can be compressed, dehydrated, and transported to suitable long-term storage locations. Depleted oil and gas fields form an attractive opportunity for long-term storage of CO2 due to the wealth of both static and dynamic knowledge available from appraisal throu","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131791483","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}
Operators are majorly focusing on zero carbon emission to comply environmental rules and regulations. This paper aims to give insights on world's major CCS project Storage Development Plan (SDP), where CO2 injection wells will be drilled to inject, and store produced CO2 from contaminated fields. To safeguard the CO2 storage containment, the integrity of all wells needs to be scrutinized. Ensuring long-term wells integrity of existing Plug and Abandonment (P&A) and active wells that penetrated the selected CO2 storage reservoir is the key to reduce leakage risks along the wellpath for long-term containment sustainability. Development wells in the identified depleted gas field are more than 30-40 years old and were not designed with any consideration of high CO2 concentration in the reservoir. Possibility of leakage along the wellbores due to accelerated corrosion, channeling, cracks, cannot be ignored and requires careful evaluation. Rigorous process has been adopted in assessing the feasibility for converting existing producers into CO2 injector. Wells disparity between the required defined basis of designs for gas producer and CO2 injection wells governs the re-usability for CO2 injection or needs to be abandoned. New three (3) CO2 injectors with fat to slim design approach, corrosion resistant alloy (CRA) material and CO2 resistant cement are designed in view to achieve lifecycle integrity. Optimum angle of 60deg and maintaining the injection pressure of 50 bar at 90MSCFD rate is required for the injection of supercritical CO2 for 25 years. On top, during well execution, challenges such as anti-collision risk, total loss scenarios while drilling in Carbonate reservoir needs to be mitigated. The completion design is also focusing on having minimal number of completion jewelries to reduce pressure differential & potential leak paths all the way from tubing hangar down to the end of lower completion. Well design optimization from fat to slim has been carried out based on WellCat sensitivity analysis output. Well integrity life cycle monitoring using in country value latest generation fiber optic as well as acquiring seismic for CO2 plume development.
{"title":"Storage Development Plan SDP for Abandoning High Risk Development Wells and Drilling Fit-For-Purpose CO2 Injectors Offshore Carbon Capture Storage CCS Project","authors":"Mahesh S. Picha, Anil Chuttani","doi":"10.2118/209884-ms","DOIUrl":"https://doi.org/10.2118/209884-ms","url":null,"abstract":"\u0000 Operators are majorly focusing on zero carbon emission to comply environmental rules and regulations. This paper aims to give insights on world's major CCS project Storage Development Plan (SDP), where CO2 injection wells will be drilled to inject, and store produced CO2 from contaminated fields. To safeguard the CO2 storage containment, the integrity of all wells needs to be scrutinized. Ensuring long-term wells integrity of existing Plug and Abandonment (P&A) and active wells that penetrated the selected CO2 storage reservoir is the key to reduce leakage risks along the wellpath for long-term containment sustainability.\u0000 Development wells in the identified depleted gas field are more than 30-40 years old and were not designed with any consideration of high CO2 concentration in the reservoir. Possibility of leakage along the wellbores due to accelerated corrosion, channeling, cracks, cannot be ignored and requires careful evaluation. Rigorous process has been adopted in assessing the feasibility for converting existing producers into CO2 injector. Wells disparity between the required defined basis of designs for gas producer and CO2 injection wells governs the re-usability for CO2 injection or needs to be abandoned. New three (3) CO2 injectors with fat to slim design approach, corrosion resistant alloy (CRA) material and CO2 resistant cement are designed in view to achieve lifecycle integrity. Optimum angle of 60deg and maintaining the injection pressure of 50 bar at 90MSCFD rate is required for the injection of supercritical CO2 for 25 years. On top, during well execution, challenges such as anti-collision risk, total loss scenarios while drilling in Carbonate reservoir needs to be mitigated. The completion design is also focusing on having minimal number of completion jewelries to reduce pressure differential & potential leak paths all the way from tubing hangar down to the end of lower completion. Well design optimization from fat to slim has been carried out based on WellCat sensitivity analysis output. Well integrity life cycle monitoring using in country value latest generation fiber optic as well as acquiring seismic for CO2 plume development.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"170 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130442990","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}
Aquatic Animal Monitoring Systemis initiated as part of PTTEP's Ocean for Life strategy as we thrive in enhancing Ocean Health & Biodiversity Monitoring to ensure that PTTEP's offshore operations are friendly and safe to the surrounding environment and aquatic animals. The basis of the Aquatic Animal Monitoring Systemproject focuses on conservation survey and tracking of rare aquatic animals as well as marinebiodiversity. As part of the process, an underwater camera was installed on a jacket leg of PTTEP's platform to allow the video recording of underwater lives. The video footage was then analyzed by Artificial Intelligence (AI)software using an object detection method for determining the animal's categorization, then using machine learning algorithm for more accuracy. This concept can visualize aquatic animals around the platform and the surrounding environment. Moreover, the AI software can shorten the video by cutting off any non-life appearing period. Therefore, this technique can support a processor during the video analysis from the platform, contributing to a better work efficiency as it can save time, manpower, and most importantly cost. For the detection algorithm, all targets generatea large amount of data in the form of images with labels in order to train a software to memorize the target objects. The AI software was able to detect and identify nine species of aquatic animals which are fish, turtle, whale, dolphin, shark, seal, sea lion, stingray, and seahorse. With AI software in place, the video raw file can be shortened up to 85% by removing non-life periods in the original video and tracking only animal life in the video frame. This is a significant milestone for PTTEP in creating sustainable values to the ocean, which is considered as PTTEP's second home. Adopting artificial intelligence and machine learning technology to this project, it helps categorizing aquatic animal types and shorten a videofile. Moreover, it can save manpower and time.
{"title":"Aquatic Animal Monitoring System","authors":"Jakkawan Sakirin, Thaniyaporn Rapeethasanaphong, Parichat Maleewong","doi":"10.2118/209933-ms","DOIUrl":"https://doi.org/10.2118/209933-ms","url":null,"abstract":"\u0000 Aquatic Animal Monitoring Systemis initiated as part of PTTEP's Ocean for Life strategy as we thrive in enhancing Ocean Health & Biodiversity Monitoring to ensure that PTTEP's offshore operations are friendly and safe to the surrounding environment and aquatic animals. The basis of the Aquatic Animal Monitoring Systemproject focuses on conservation survey and tracking of rare aquatic animals as well as marinebiodiversity.\u0000 As part of the process, an underwater camera was installed on a jacket leg of PTTEP's platform to allow the video recording of underwater lives. The video footage was then analyzed by Artificial Intelligence (AI)software using an object detection method for determining the animal's categorization, then using machine learning algorithm for more accuracy. This concept can visualize aquatic animals around the platform and the surrounding environment. Moreover, the AI software can shorten the video by cutting off any non-life appearing period. Therefore, this technique can support a processor during the video analysis from the platform, contributing to a better work efficiency as it can save time, manpower, and most importantly cost.\u0000 For the detection algorithm, all targets generatea large amount of data in the form of images with labels in order to train a software to memorize the target objects. The AI software was able to detect and identify nine species of aquatic animals which are fish, turtle, whale, dolphin, shark, seal, sea lion, stingray, and seahorse. With AI software in place, the video raw file can be shortened up to 85% by removing non-life periods in the original video and tracking only animal life in the video frame. This is a significant milestone for PTTEP in creating sustainable values to the ocean, which is considered as PTTEP's second home.\u0000 Adopting artificial intelligence and machine learning technology to this project, it helps categorizing aquatic animal types and shorten a videofile. Moreover, it can save manpower and time.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"2015 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127613288","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. Zhan, Abdulwahab S. Aljohar, Jianhui Xu, Bodong Li, Huijuan Guo
The monobore solid expandable tubular (MSET) system, which maintains the same drift as the previous casing and enables the operator to maintain an original drilling plan to total depth, is the next generation solid expandable tubular technology - the most advanced expandable liner system available typically to isolate severe losses or trouble zones while drilling. To address the major technical challenges of a large expansion ratio required to meet MSET requirement, and able to deliver potential longer MSET liner without a concern of premature expansion problem, this paper presents an innovative solution consisting of a safe release mechanism (SRM) for running MSET incorporating a dual-stage expansion mechanism. This paper presents an innovative approach to the reliability of this mechanism based on Finite Element Analysis (FEA) simulation and indoor tests, as well as a dual-stage expansion process. The dual-stage expansion offers the advantage of a relative ease on the expandable thread when undergoing a large physical expansion, and therefore leads to a less risk of thread failure during the expansion process. The new SRM transfers the weight of the MSET from the cone surface to a collet-finger type plug-in structure, which can be unlocked by hydraulic pressure when the MSET is run to the intended depth. Based on the result of simulation, an indoor test was conducted and the load capacity of SRM was up to 109 tons, which is safe for at least 1,000 ft MSET. The newly developed tubular with proprietary expandable thread was successfully deployed with a better than expected quality, enabling a successful run of quite long 2,250 feet expandable liner with a steady expansion pressure, and post expansion pressure test without any problem, and as expected, delivered a designed post expansion pipe ID. Most importantly the deployment of expandable liner resolved the severe loss drilling problem, enabled to raise mud weight from 1.05g/cm3 to 1.78g/ cm3,met the requirement of allowing drilling with 190.5mm (7-1/2″) bit and enabled drilling operation to resume and continue drilling a horizontal section without any major problem. This paper presents a combined (computer simulation and indoor tests for calibration) approach to conducting an advanced monobore solid expandable tubular technology development. The innovative safe release mechanism and dual-stage expansion process assures the application success of the MSET system in optimizing well casing designs for effectively addressing challenges in severe drilling losses.
{"title":"Innovative Monobore Solid Expandable Tubular System for Isolating Severe Losses","authors":"G. Zhan, Abdulwahab S. Aljohar, Jianhui Xu, Bodong Li, Huijuan Guo","doi":"10.2118/209852-ms","DOIUrl":"https://doi.org/10.2118/209852-ms","url":null,"abstract":"\u0000 The monobore solid expandable tubular (MSET) system, which maintains the same drift as the previous casing and enables the operator to maintain an original drilling plan to total depth, is the next generation solid expandable tubular technology - the most advanced expandable liner system available typically to isolate severe losses or trouble zones while drilling. To address the major technical challenges of a large expansion ratio required to meet MSET requirement, and able to deliver potential longer MSET liner without a concern of premature expansion problem, this paper presents an innovative solution consisting of a safe release mechanism (SRM) for running MSET incorporating a dual-stage expansion mechanism.\u0000 This paper presents an innovative approach to the reliability of this mechanism based on Finite Element Analysis (FEA) simulation and indoor tests, as well as a dual-stage expansion process. The dual-stage expansion offers the advantage of a relative ease on the expandable thread when undergoing a large physical expansion, and therefore leads to a less risk of thread failure during the expansion process. The new SRM transfers the weight of the MSET from the cone surface to a collet-finger type plug-in structure, which can be unlocked by hydraulic pressure when the MSET is run to the intended depth.\u0000 Based on the result of simulation, an indoor test was conducted and the load capacity of SRM was up to 109 tons, which is safe for at least 1,000 ft MSET. The newly developed tubular with proprietary expandable thread was successfully deployed with a better than expected quality, enabling a successful run of quite long 2,250 feet expandable liner with a steady expansion pressure, and post expansion pressure test without any problem, and as expected, delivered a designed post expansion pipe ID. Most importantly the deployment of expandable liner resolved the severe loss drilling problem, enabled to raise mud weight from 1.05g/cm3 to 1.78g/ cm3,met the requirement of allowing drilling with 190.5mm (7-1/2″) bit and enabled drilling operation to resume and continue drilling a horizontal section without any major problem.\u0000 This paper presents a combined (computer simulation and indoor tests for calibration) approach to conducting an advanced monobore solid expandable tubular technology development. The innovative safe release mechanism and dual-stage expansion process assures the application success of the MSET system in optimizing well casing designs for effectively addressing challenges in severe drilling losses.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"107 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116371789","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}
Hamdi Mohamad, Felicity Anai Anak Michael Mulok, Douwe Franssens, Nurfitrah Mat Noh, Diego Patino, Janna Tiong Mang Ing
Currently, Automated Reporting leverages rig-sensors to produce ‘Activity’ and populated the Daily Drilling Report (DDR), replacing the labour-intensive manual entries. However, Surface and non-drilling activities cannot be detected in this way. The case study documents the complimentary use of a digital execution platform in filling these gaps. The automated daily drilling reporting solely on real-time rig sensors input causes a substantial number of non-drilling activities to be excluded and the data is not sufficient to produce solid 24-hour activities as required. Therefore, this paper presents a reporting solution that combines both real-time rig sensors input and activity tracking from a digital execution platform thus enabling the next level of reporting automation. Furthermore, the combination of these two sources ensures reporting accuracy and provides granularity for the next level of performance benchmarking. The paper documents the vision, methodology, implementation steps, challenges, and benefits of automating daily drilling reporting. The results of the case study were thoroughly discussed. The overall approach that was undertaken is straightforward where observation was conducted by identifying the similarity and differences of activities detected in the manual DDR and the improved automated reporting activities. The gap between the drilling activities (rig states) and non-drilling activities is corrected through a process of "cut and split" to capture the 24 hours activities. The planned activities were imported and monitored in the Digital Execution Platform, translated into WITSML (Wellsite Information Transfer Standard Markup Language) Drillreport object. Simultaneously, the real-time rig sensors data are available as WITSML log objects. DrillOps Report executes three tasks: Populate the sensor activities (Referred to as Automated Rig State Activity) by utilizing the "Fixed Text Remark" capability.Filter DrillReport object for actual activities on the rig marked as completed (Referred to as External Activity) by supervisors on the rig to populate all valid activities on rig.Overlapped activities in (1) and (2) will be cut and split accordingly where (1) supersedes the (2) as the single source of truth is the rig states detected by the rig sensors. On non-drilling days, (2) supersedes. This is referred to as Machine Activity Record (MAR). Other DDR information required is populated via FileBridge where the readily available information is parsed from the contractors' own reports into Automated Operational Reporting Solution. By utilizing the automated daily drilling reporting capabilities, rigsite users were able to reduce the time spent in capturing and entering the information required as part of the DDR. The rigsite personnel was then able to direct their attention on running daily data QA/QC prior to the daily report submission. This then allows them to put more focus on optimizing their wellsite operational performan
目前,自动化报告利用钻机传感器生成“活动”并填充每日钻井报告(DDR),取代了劳动密集型的人工输入。然而,地面和非钻井活动无法通过这种方式检测到。该案例研究记录了数字执行平台在填补这些空白方面的免费使用。仅根据实时钻机传感器输入的自动每日钻井报告导致大量非钻井活动被排除在外,数据不足以产生所需的24小时稳定活动。因此,本文提出了一种报告解决方案,结合了实时钻机传感器输入和数字执行平台的活动跟踪,从而实现了更高水平的报告自动化。此外,这两个来源的组合确保了报告的准确性,并为下一级性能基准测试提供了粒度。该文件记录了自动化每日钻井报告的愿景、方法、实施步骤、挑战和好处。对案例研究的结果进行了深入的讨论。所采取的总体方法是直接的,通过确定在手动DDR和改进的自动报告活动中检测到的活动的相似性和差异性来进行观察。钻井活动(钻机状态)和非钻井活动之间的差距通过“切割和分割”过程来纠正,以捕获24小时的活动。计划的活动在数字执行平台中被导入和监控,并转化为WITSML(井场信息传输标准标记语言)钻井报告对象。同时,实时钻机传感器数据可作为WITSML测井对象使用。drilllops Report执行三个任务:利用“Fixed Text Remark”功能填充传感器活动(称为自动化钻机状态活动)。过滤DrillReport对象,将钻机上的实际活动标记为已完成(称为外部活动),以填充钻机上的所有有效活动。(1)和(2)中的重叠活动将被相应地切割和分割,其中(1)取代(2),因为事实的单一来源是钻机传感器检测到的钻机状态。在非钻井日,(2)取代。这被称为机器活动记录(MAR)。其他所需的DDR信息通过FileBridge进行填充,在FileBridge中,可以将承包商自己的报告中的现成信息解析为自动化操作报告解决方案。通过利用自动化的每日钻井报告功能,现场用户能够减少捕获和输入DDR所需信息所花费的时间。在提交日常报告之前,现场人员可以将注意力集中在运行日常数据QA/QC上。这使得他们能够更加专注于优化井场作业性能,并计划当前活动的任何潜在结果。结构化数据将使钻井后的可操作洞察分析成为可能。
{"title":"Innovative Automated Data Driven Daily Drilling Reporting Using Automated Data-Driven Models and a Digital Execution Platform","authors":"Hamdi Mohamad, Felicity Anai Anak Michael Mulok, Douwe Franssens, Nurfitrah Mat Noh, Diego Patino, Janna Tiong Mang Ing","doi":"10.2118/209894-ms","DOIUrl":"https://doi.org/10.2118/209894-ms","url":null,"abstract":"\u0000 Currently, Automated Reporting leverages rig-sensors to produce ‘Activity’ and populated the Daily Drilling Report (DDR), replacing the labour-intensive manual entries. However, Surface and non-drilling activities cannot be detected in this way. The case study documents the complimentary use of a digital execution platform in filling these gaps. The automated daily drilling reporting solely on real-time rig sensors input causes a substantial number of non-drilling activities to be excluded and the data is not sufficient to produce solid 24-hour activities as required. Therefore, this paper presents a reporting solution that combines both real-time rig sensors input and activity tracking from a digital execution platform thus enabling the next level of reporting automation. Furthermore, the combination of these two sources ensures reporting accuracy and provides granularity for the next level of performance benchmarking. The paper documents the vision, methodology, implementation steps, challenges, and benefits of automating daily drilling reporting. The results of the case study were thoroughly discussed.\u0000 The overall approach that was undertaken is straightforward where observation was conducted by identifying the similarity and differences of activities detected in the manual DDR and the improved automated reporting activities. The gap between the drilling activities (rig states) and non-drilling activities is corrected through a process of \"cut and split\" to capture the 24 hours activities. The planned activities were imported and monitored in the Digital Execution Platform, translated into WITSML (Wellsite Information Transfer Standard Markup Language) Drillreport object. Simultaneously, the real-time rig sensors data are available as WITSML log objects.\u0000 DrillOps Report executes three tasks: Populate the sensor activities (Referred to as Automated Rig State Activity) by utilizing the \"Fixed Text Remark\" capability.Filter DrillReport object for actual activities on the rig marked as completed (Referred to as External Activity) by supervisors on the rig to populate all valid activities on rig.Overlapped activities in (1) and (2) will be cut and split accordingly where (1) supersedes the (2) as the single source of truth is the rig states detected by the rig sensors. On non-drilling days, (2) supersedes. This is referred to as Machine Activity Record (MAR).\u0000 Other DDR information required is populated via FileBridge where the readily available information is parsed from the contractors' own reports into Automated Operational Reporting Solution.\u0000 By utilizing the automated daily drilling reporting capabilities, rigsite users were able to reduce the time spent in capturing and entering the information required as part of the DDR. The rigsite personnel was then able to direct their attention on running daily data QA/QC prior to the daily report submission. This then allows them to put more focus on optimizing their wellsite operational performan","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126787150","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}