Mohamed M. Atia, A. Abdelkhalek, A. Sarkar, M. Keys, M. Patel, Mohammed Eissa, Tarek Omar
Managing a large fleet of offshore structures is a dynamic process that aims at minimising risks to personnel, environment, and businesses, as well as minimising the associated Operations Expenditure. Through the collaborative efforts of ADNOC Offshore and Kent, formerly Atkins Oil & Gas, (Atkins, 2020), revised structural evaluation and integrity approaches have yielded significant cost savings. The considerable savings were associated with the elimination of the requirement for installing many new offshore structures and through reducing the subsea inspection associated efforts. The approach for evaluating the offshore assets’ structural performance was developed based on adopting target probability of failure figures subject to each asset's consequence of failure. Accordingly, structural reliability analyses were conducted specific to each structure, where the analysis considered structure specific environmental hazard curves and failure surfaces. Through mapping the evaluated structural probability of failure and ADNOC's corporate risk matrix's HSE Likelihood, each structure was precisely placed on the risk matrix. Furthermore, the inspection intervals and Topsides, Splash Zone, Subsea Levels I, II and III were mapped to each risk evaluation on the risk matrix. The optimisation approach of adopting a structure specific reliability analysis and mapping with ADNOC's corporate risk matrix yielded considerable cost benefits while providing a more accurate representation of each asset's risk. As a result of the implementation of the developed process, approximately 41% of the assets got lower risk evaluation compared to the legacy approach and presented extra structural capacities that can be utilised for future expansions and eliminating the requirement for installation of new assets. As the process expanded to include asset inspections, the subsea inspection requirements reduced by approximately 43% reflecting a considerable decrease in operating costs. A major contribution of the risk improvement is attributed to the consideration of the storm prevailing approach directions, the joint probability of wave and current magnitudes and directions, as well as the relative alignment of each structure. The developed approaches provide a framework that allows continuous update of the risk assessment and enables executives and management to make risk-based-decision supported by a consistent measure of structural risk. This has been translated into the generation of the Structural Passports (Summary reports) clearly demonstrating the assets current risk and recommendations for mitigation measures, if deemed required.
{"title":"Reliability Based Structural Risk Assessments and Associated Economic Gains","authors":"Mohamed M. Atia, A. Abdelkhalek, A. Sarkar, M. Keys, M. Patel, Mohammed Eissa, Tarek Omar","doi":"10.2118/207810-ms","DOIUrl":"https://doi.org/10.2118/207810-ms","url":null,"abstract":"\u0000 Managing a large fleet of offshore structures is a dynamic process that aims at minimising risks to personnel, environment, and businesses, as well as minimising the associated Operations Expenditure. Through the collaborative efforts of ADNOC Offshore and Kent, formerly Atkins Oil & Gas, (Atkins, 2020), revised structural evaluation and integrity approaches have yielded significant cost savings. The considerable savings were associated with the elimination of the requirement for installing many new offshore structures and through reducing the subsea inspection associated efforts.\u0000 The approach for evaluating the offshore assets’ structural performance was developed based on adopting target probability of failure figures subject to each asset's consequence of failure. Accordingly, structural reliability analyses were conducted specific to each structure, where the analysis considered structure specific environmental hazard curves and failure surfaces.\u0000 Through mapping the evaluated structural probability of failure and ADNOC's corporate risk matrix's HSE Likelihood, each structure was precisely placed on the risk matrix. Furthermore, the inspection intervals and Topsides, Splash Zone, Subsea Levels I, II and III were mapped to each risk evaluation on the risk matrix.\u0000 The optimisation approach of adopting a structure specific reliability analysis and mapping with ADNOC's corporate risk matrix yielded considerable cost benefits while providing a more accurate representation of each asset's risk. As a result of the implementation of the developed process, approximately 41% of the assets got lower risk evaluation compared to the legacy approach and presented extra structural capacities that can be utilised for future expansions and eliminating the requirement for installation of new assets. As the process expanded to include asset inspections, the subsea inspection requirements reduced by approximately 43% reflecting a considerable decrease in operating costs.\u0000 A major contribution of the risk improvement is attributed to the consideration of the storm prevailing approach directions, the joint probability of wave and current magnitudes and directions, as well as the relative alignment of each structure.\u0000 The developed approaches provide a framework that allows continuous update of the risk assessment and enables executives and management to make risk-based-decision supported by a consistent measure of structural risk. This has been translated into the generation of the Structural Passports (Summary reports) clearly demonstrating the assets current risk and recommendations for mitigation measures, if deemed required.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78210875","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. Mujiyanto, A. Wicaksono, Fonny Prasmono Adhi, M. S. Missuari
To achieve 24% portion of natural gas in targeted national energy mix in 2050, Indonesia government has integrated Pertagas, biggest transmission company into PGN, biggest distribution company under Oil & Gas Holding Pertamina. But survey from PWC in 2004 resulted that around 75% post-merger companies reported integration difficulties, especially both companies have long history of competition. Even more, government mandated 6 USD gas price policy at plant gate, which create enormous urgency to accelerate pipeline and digital integration in the most efficient way. Especially, in this pandemic era, midstream industry needs to foster digital transformation by rethinking outdated business models and strategically applying technology to change rather than focusing on simply cutting costs. From this integration, Pertagas with more than 2,418 km pipeline in 12 provinces spread from Sumatra, Java and Kalimantan has a big potency to be synergized with PGN, as Sub Holding Gas with the total of 10,169 km of pipeline which represent 96% of national gas infrastructure. During 2020. Both companies resulted more than 1.255 MMSCFD of transported gas and 828 BBTUD of sales gas to more than 460 thousand customers. So, PGN and Pertagas management has high expectation on this digital integration to transform from previous fragmented pipeline to be interconnected network to give flexibility in reaching unmet growing demand of strategic industry like refinery, fertilizer, electricity, steel and petrochemical in post-COVID recovery. In this paper, will be described the challenges and its solutions as a success story in digital integration. The important steps start from strategy development, digital assessment, creating coalition, culture acculturation, and change management are explained as guiding pathway for sustainable implementation. It will also portray the measured benefit and value from investment cost efficiency, time effectiveness from the initiation until launched, billing improvement, product development, and up to developed real-time integrated management dashboard for better decision making and part of the milestone for future National Dispatching Center for optimizing Sub Holding Gas portfolio of gas supply and subsidiary's infrastructure to meet growing Indonesia's demand.
{"title":"Digital Integration, Success Story of Accelerating Business Integration of Two Biggest Midstream-Downstream Natural Gas Company in Indonesia","authors":"A. Mujiyanto, A. Wicaksono, Fonny Prasmono Adhi, M. S. Missuari","doi":"10.2118/207321-ms","DOIUrl":"https://doi.org/10.2118/207321-ms","url":null,"abstract":"To achieve 24% portion of natural gas in targeted national energy mix in 2050, Indonesia government has integrated Pertagas, biggest transmission company into PGN, biggest distribution company under Oil & Gas Holding Pertamina. But survey from PWC in 2004 resulted that around 75% post-merger companies reported integration difficulties, especially both companies have long history of competition. Even more, government mandated 6 USD gas price policy at plant gate, which create enormous urgency to accelerate pipeline and digital integration in the most efficient way. Especially, in this pandemic era, midstream industry needs to foster digital transformation by rethinking outdated business models and strategically applying technology to change rather than focusing on simply cutting costs. From this integration, Pertagas with more than 2,418 km pipeline in 12 provinces spread from Sumatra, Java and Kalimantan has a big potency to be synergized with PGN, as Sub Holding Gas with the total of 10,169 km of pipeline which represent 96% of national gas infrastructure. During 2020. Both companies resulted more than 1.255 MMSCFD of transported gas and 828 BBTUD of sales gas to more than 460 thousand customers. So, PGN and Pertagas management has high expectation on this digital integration to transform from previous fragmented pipeline to be interconnected network to give flexibility in reaching unmet growing demand of strategic industry like refinery, fertilizer, electricity, steel and petrochemical in post-COVID recovery. In this paper, will be described the challenges and its solutions as a success story in digital integration. The important steps start from strategy development, digital assessment, creating coalition, culture acculturation, and change management are explained as guiding pathway for sustainable implementation. It will also portray the measured benefit and value from investment cost efficiency, time effectiveness from the initiation until launched, billing improvement, product development, and up to developed real-time integrated management dashboard for better decision making and part of the milestone for future National Dispatching Center for optimizing Sub Holding Gas portfolio of gas supply and subsidiary's infrastructure to meet growing Indonesia's demand.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78378478","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}
Sujet Phodapol, Tachadol Suthisomboon, P. Kosanunt, Ravipas Vongasemjit, P. Janbanjong, P. Manoonpong
Passive and active hybrid pipeline inspection gauges (PIGs) have been used for in-pipe inspection. While a passive PIG cannot control its speed, the hybrid version can achieve this by using an integrated valve specifically designed and embedded in the PIG. This study proposes a generic new method for speed adaptation in PIGs (called MC-PIG) by introducing a generic, modular, controllable, external valve unit add-on for attaching to existing conventional (passive) PIGs with minimal change. The MC-PIG method is based on the principle of morphological computation with closed-loop control. It is achieved by regulating/computing the PIG's morphology (i.e., a modular rotary valve unit add-on) to control bypass flow. Adjustment of the valve angle can affect the flow rate passing through the PIG, resulting in speed regulation ability. We use numerical simulation with computational fluid dynamics (CFD) to investigate and analyze the speed of a simulated PIG with the valve unit adjusted by proportional-integral (PI) control under various in-pipe pressure conditions. Our simulation experiments are performed under different operating conditions in three pipe sizes (16″, 18″, and 22″ in diameter) to manifest the speed adaptation of the PIG with the modular valve unit add-on and PI control. Our results show that the PIG can effectively perform real-time adaptation (i.e., adjusting its valve angle) to maintain the desired speed. The valve design can be adjusted from 5 degrees (closed valve, resulting in high moving speed) to a maximum of 45 degrees (fully open valve, resulting in low moving speed). The speed of the PIG can be regulated from 0.59 m/s to 3.88 m/s in a 16″ pipe at 4.38 m/s (in-pipe fluid velocity), 2500 kPa (operating pressure), and 62 °C (operating temperature). Finally, the MC-PIG method is validated using a 3D-printed prototype in a 6″ pipe. Through the investigation, we observed that two factors influence speed adaptation; the pressure drop coefficient and friction of the PIG and pipeline. In conclusion, the results from the simulation and prototype show close characteristics with an acceptable error.
{"title":"Morphological Adaptation for Speed Control of Pipeline Inspection Gauges MC-PIG","authors":"Sujet Phodapol, Tachadol Suthisomboon, P. Kosanunt, Ravipas Vongasemjit, P. Janbanjong, P. Manoonpong","doi":"10.2118/207403-ms","DOIUrl":"https://doi.org/10.2118/207403-ms","url":null,"abstract":"\u0000 Passive and active hybrid pipeline inspection gauges (PIGs) have been used for in-pipe inspection. While a passive PIG cannot control its speed, the hybrid version can achieve this by using an integrated valve specifically designed and embedded in the PIG. This study proposes a generic new method for speed adaptation in PIGs (called MC-PIG) by introducing a generic, modular, controllable, external valve unit add-on for attaching to existing conventional (passive) PIGs with minimal change. The MC-PIG method is based on the principle of morphological computation with closed-loop control. It is achieved by regulating/computing the PIG's morphology (i.e., a modular rotary valve unit add-on) to control bypass flow. Adjustment of the valve angle can affect the flow rate passing through the PIG, resulting in speed regulation ability. We use numerical simulation with computational fluid dynamics (CFD) to investigate and analyze the speed of a simulated PIG with the valve unit adjusted by proportional-integral (PI) control under various in-pipe pressure conditions. Our simulation experiments are performed under different operating conditions in three pipe sizes (16″, 18″, and 22″ in diameter) to manifest the speed adaptation of the PIG with the modular valve unit add-on and PI control. Our results show that the PIG can effectively perform real-time adaptation (i.e., adjusting its valve angle) to maintain the desired speed. The valve design can be adjusted from 5 degrees (closed valve, resulting in high moving speed) to a maximum of 45 degrees (fully open valve, resulting in low moving speed). The speed of the PIG can be regulated from 0.59 m/s to 3.88 m/s in a 16″ pipe at 4.38 m/s (in-pipe fluid velocity), 2500 kPa (operating pressure), and 62 °C (operating temperature). Finally, the MC-PIG method is validated using a 3D-printed prototype in a 6″ pipe. Through the investigation, we observed that two factors influence speed adaptation; the pressure drop coefficient and friction of the PIG and pipeline. In conclusion, the results from the simulation and prototype show close characteristics with an acceptable error.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80004592","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Machocki, Abdulwahab S. Aljohar, David Z. Zhan, Ayodeji Abegunde
A new down hole system and method to use for releasing stuck pipes is presented. New system design, features and limits are compared to commonly used techniques for releasing stuck pipe showing benefits of the new system when dealing with differential stuck pipe incidents. The new down hole system is capable to deliver much greater forces when compared to jars and other down hole accelerators near the stuck point. This system can generate over 40G`s lateral forces continuously down the hole acting on the stuck pipe area. The system can be integrated into a Bottom Hole Assembly (BHA) and activated once drill string become stuck or run as a part of the remediate assembly. Different aspects of two types of assemblies are described outlining the benefits and drawbacks. The author will discuss in details the background and rationale to the new technology, including a review of differential sticking challenges and functionality of this new system. The new system was compared to the most commonly used techniques for releasing differentially stuck pipe. Previously not releasable stuck pipe forces of over 1,000,000 lb. can now be overcome with the presented new approach to generate down hole forces near the stuck place. Flexibility in system integration and deployment allows for further optimization in BHA design and cost affective fishing operations in dedicated hole sections. This new approach can be implemented to release the most challenging stuck pipe mechanisms in drilling to minimize NPT and cost associated with stuck pipe, remedial operations and sidetracks. Similar approach can be utilized to release differentially stuck pipes, tubing and completions. The novelty of this stuck pipe release system is the entire down hole system and operations of the overall system using new approach to generate large shocks down the hole. Additional novelty is related to flexibility during integration and deployment of this system. Similar to current shock tools, this system can be placed in BHA, fishing type assemblies and also pumped down inside of the stuck drill string to save time and cost.
{"title":"A New Down Hole Tool and Approach To Release Differentially Stuck Pipe","authors":"K. Machocki, Abdulwahab S. Aljohar, David Z. Zhan, Ayodeji Abegunde","doi":"10.2118/207964-ms","DOIUrl":"https://doi.org/10.2118/207964-ms","url":null,"abstract":"\u0000 A new down hole system and method to use for releasing stuck pipes is presented. New system design, features and limits are compared to commonly used techniques for releasing stuck pipe showing benefits of the new system when dealing with differential stuck pipe incidents.\u0000 The new down hole system is capable to deliver much greater forces when compared to jars and other down hole accelerators near the stuck point. This system can generate over 40G`s lateral forces continuously down the hole acting on the stuck pipe area. The system can be integrated into a Bottom Hole Assembly (BHA) and activated once drill string become stuck or run as a part of the remediate assembly. Different aspects of two types of assemblies are described outlining the benefits and drawbacks.\u0000 The author will discuss in details the background and rationale to the new technology, including a review of differential sticking challenges and functionality of this new system.\u0000 The new system was compared to the most commonly used techniques for releasing differentially stuck pipe. Previously not releasable stuck pipe forces of over 1,000,000 lb. can now be overcome with the presented new approach to generate down hole forces near the stuck place. Flexibility in system integration and deployment allows for further optimization in BHA design and cost affective fishing operations in dedicated hole sections. This new approach can be implemented to release the most challenging stuck pipe mechanisms in drilling to minimize NPT and cost associated with stuck pipe, remedial operations and sidetracks. Similar approach can be utilized to release differentially stuck pipes, tubing and completions.\u0000 The novelty of this stuck pipe release system is the entire down hole system and operations of the overall system using new approach to generate large shocks down the hole. Additional novelty is related to flexibility during integration and deployment of this system. Similar to current shock tools, this system can be placed in BHA, fishing type assemblies and also pumped down inside of the stuck drill string to save time and cost.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"200 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77982799","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}
Yang Wu, O. Sørensen, Nabila Lazreq, Yin Luo, T. Bukovac, V. Arali
Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.
{"title":"Zipper Fracturing of Horizontal Cluster Wells: Game Changing Unconventional Fracturing in UAE","authors":"Yang Wu, O. Sørensen, Nabila Lazreq, Yin Luo, T. Bukovac, V. Arali","doi":"10.2118/207523-ms","DOIUrl":"https://doi.org/10.2118/207523-ms","url":null,"abstract":"\u0000 Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence \"zipper fracturing\" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance.\u0000 The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities.\u0000 With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm.\u0000 The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86381907","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Moreno, Yunlong Liu, Oluwale Talabi, O. Gurpinar, M. Kristensen, G. Goh, M. Paydayesh
Challenges in the design of efficient EOR field pilots have been discussed and documented in the industry, particularly when it comes to optimization of monitoring plans for technical and economical perspectives. This paper explores the benefits of pilot planning where the monitoring/control strategies are included in the early stages of the design to reduce risk of measurements ambiguity and ensure good quality pilot results evaluation. It addresses the use of new and existing technology in monitoring by highlighting the advantages and challenges of each alternative including potential pairing of complementary options to achieve the pilot objectives including illustration of the use of continuous and sporadic measurements on the evaluation. The proposed approach starts with a review of reservoir performance, heterogeneity and pilot objectives to ascertain the plausible monitoring technologies/strategies to aid during the pilot de-risking, followed by the identification of adequate novel and mature monitoring options, which are specific to EOR type and measurement nature (permanent, time lapse, etc.). Advantages of incorporating the monitoring strategy as integral part of the pilot design, as well as evaluation of the effectiveness/viability in the presence of uncertainty of the selected monitoring alternatives are discussed providing a reference of suitable/plausible EOR specific technologies. The paper illustrates the importance of selecting monitoring alternatives that feed off each other and the importance of using fit-for-purpose evaluation algorithms and a digitally enabled, structured approach to analyze and democratize pilot results and enable actionable decisions in operations.
{"title":"Impact of Fit-for-Purpose Monitoring on EOR Planning","authors":"J. Moreno, Yunlong Liu, Oluwale Talabi, O. Gurpinar, M. Kristensen, G. Goh, M. Paydayesh","doi":"10.2118/207937-ms","DOIUrl":"https://doi.org/10.2118/207937-ms","url":null,"abstract":"\u0000 Challenges in the design of efficient EOR field pilots have been discussed and documented in the industry, particularly when it comes to optimization of monitoring plans for technical and economical perspectives. This paper explores the benefits of pilot planning where the monitoring/control strategies are included in the early stages of the design to reduce risk of measurements ambiguity and ensure good quality pilot results evaluation. It addresses the use of new and existing technology in monitoring by highlighting the advantages and challenges of each alternative including potential pairing of complementary options to achieve the pilot objectives including illustration of the use of continuous and sporadic measurements on the evaluation.\u0000 The proposed approach starts with a review of reservoir performance, heterogeneity and pilot objectives to ascertain the plausible monitoring technologies/strategies to aid during the pilot de-risking, followed by the identification of adequate novel and mature monitoring options, which are specific to EOR type and measurement nature (permanent, time lapse, etc.). Advantages of incorporating the monitoring strategy as integral part of the pilot design, as well as evaluation of the effectiveness/viability in the presence of uncertainty of the selected monitoring alternatives are discussed providing a reference of suitable/plausible EOR specific technologies. The paper illustrates the importance of selecting monitoring alternatives that feed off each other and the importance of using fit-for-purpose evaluation algorithms and a digitally enabled, structured approach to analyze and democratize pilot results and enable actionable decisions in operations.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83089338","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}
Mohammad Rasheed Khan, G. Glatz, D. Gwaba, G. Aidagulov
More than two decades have passed since the introduction of the scratch testing method for rock strength determination. The test method typically involves dragging a rigid-shaped cutter across the rock surface at a fixed cutting depth. This depth determines the failure mechanism of the rock, ductile for shallow depths and brittle for deeper. In the ductile mode, intrinsic specific energy is primarily a measure of the unconfined-compressive-strength (UCS), which is pivotal for rate of penetration (ROP) during drilling and for borehole stability analysis. On the contrary, brittle failure can lead to permanent core damage and is usually not desired as it impacts interpretation of the scratch testing results. Consequently, it is imperative to identify the critical depth, and at which transition from ductile to brittle failure occurs which will help optimize rock testing and tool designs. In this study, a novel methodology is proposed utilizing micro-computed tomography (CT) imaging to determine critical depth through morphological analysis of scratch test cuttings. Scratch tests are carried out on Indiana limestone core samples with the cutter-rock interaction geometry characterized by a cutter width of 10mm and a back-rake angle of 15°. The sample is scratched in the range of 0.05mm to 0.40mm with increments of 0.05mm. Scratch powder is carefully collected after each scratch increment and stored for further analysis. This powder is then loaded into slim rubber tubes and imaged at a high resolution of 1 µm with a helical micro-CT scanner. The scans are then reconstructed using a computer program to initiate the visualization of individual grains from each cutter depth including evaluation of grain morphologies. Finally, the results from this morphological analysis are corroborated and compared with three other methods: force response analysis, force inflection point analysis, and the size effect law (SEL). Based on shape analysis, it was found that the transition from ductile to brittle regime occurs at a depth of 0.25mm. Elongation and appearance of the enhanced degree of angularity of the grains as the depth of cut (DOC) increases past 0.25mm was observed. Moreover, large grain sizes were detected and are representative of formation of chips (typical brittle regime response). Furthermore, it is illustrated that the image analysis helps eliminate the ambiguity of force signal analysis and in combination can aid in the critical depth of cut determination. The other methods involving force alone and the SEL are not able to pin-point onset of brittle regime. Using a similar methodology, creation of a database for various rock types is recommended to develop a guide for the depth of cut selection during scratch testing. This novel methodology utilizing micro-CT analysis and comparative study with other techniques will put in place an accurate strategy to determine the critical depth of cut when designing rock scratch testing programs.
{"title":"A Novel Methodology to Investigate Critical Depth for Ductile-to-Brittle Transition During Scratch Testing","authors":"Mohammad Rasheed Khan, G. Glatz, D. Gwaba, G. Aidagulov","doi":"10.2118/207409-ms","DOIUrl":"https://doi.org/10.2118/207409-ms","url":null,"abstract":"\u0000 More than two decades have passed since the introduction of the scratch testing method for rock strength determination. The test method typically involves dragging a rigid-shaped cutter across the rock surface at a fixed cutting depth. This depth determines the failure mechanism of the rock, ductile for shallow depths and brittle for deeper. In the ductile mode, intrinsic specific energy is primarily a measure of the unconfined-compressive-strength (UCS), which is pivotal for rate of penetration (ROP) during drilling and for borehole stability analysis. On the contrary, brittle failure can lead to permanent core damage and is usually not desired as it impacts interpretation of the scratch testing results. Consequently, it is imperative to identify the critical depth, and at which transition from ductile to brittle failure occurs which will help optimize rock testing and tool designs. In this study, a novel methodology is proposed utilizing micro-computed tomography (CT) imaging to determine critical depth through morphological analysis of scratch test cuttings.\u0000 Scratch tests are carried out on Indiana limestone core samples with the cutter-rock interaction geometry characterized by a cutter width of 10mm and a back-rake angle of 15°. The sample is scratched in the range of 0.05mm to 0.40mm with increments of 0.05mm. Scratch powder is carefully collected after each scratch increment and stored for further analysis. This powder is then loaded into slim rubber tubes and imaged at a high resolution of 1 µm with a helical micro-CT scanner. The scans are then reconstructed using a computer program to initiate the visualization of individual grains from each cutter depth including evaluation of grain morphologies. Finally, the results from this morphological analysis are corroborated and compared with three other methods: force response analysis, force inflection point analysis, and the size effect law (SEL).\u0000 Based on shape analysis, it was found that the transition from ductile to brittle regime occurs at a depth of 0.25mm. Elongation and appearance of the enhanced degree of angularity of the grains as the depth of cut (DOC) increases past 0.25mm was observed. Moreover, large grain sizes were detected and are representative of formation of chips (typical brittle regime response). Furthermore, it is illustrated that the image analysis helps eliminate the ambiguity of force signal analysis and in combination can aid in the critical depth of cut determination. The other methods involving force alone and the SEL are not able to pin-point onset of brittle regime. Using a similar methodology, creation of a database for various rock types is recommended to develop a guide for the depth of cut selection during scratch testing.\u0000 This novel methodology utilizing micro-CT analysis and comparative study with other techniques will put in place an accurate strategy to determine the critical depth of cut when designing rock scratch testing programs.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87834120","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. Najaf, M. Al-Haddad, A. Al-Dhafiri, Omar Al-Anezi, M. Bu-mijdad, S. Jalan, F. Snasiri, Jorge Munoz, Sarah Al Azmi, A. Salem, Ahmad Lari, E. Bespalov, Luis Gomez, N. Molero, V. Pochetnyy, Tuleen Nazzal
With the continuous production from Kuwait oil reservoirs, a clear decline in reservoir pressure is observed. Subsequently, the demand for artificial lift is increasing to sustain production. Maintenance of those wells requires frequent interventions and continuous presence of workover rigs, which affects overall cost of production. Change of the electrical submersible pump (ESP) deployment method represents one of the cost reduction initiatives undertaken by the operator to reduce well intervention time and improve asset utilization. To minimize deferred production generated by the ESP replacement operation, a novel rigless approach leveraging coiled tubing (CT) was introduced in southeast and west Kuwait. It reduces operating costs and eliminates disruptions to operations by enabling rigless retrieval and redeployment of a standard ESP assembly. To evaluate the efficiency of using CT as rigless ESP retrieval and conveyance method, two candidate wells were selected to recover and redeploy a 108-ft-long ESP system. The intervention methodology relied on CT equipped with optical line and real-time downhole telemetry, a high-pressure rotary jetting tool, and a specific ESP deployment assembly. The retrieval and redeployment of the ESP was executed in a single rigless intervention, averaging less than 72 hours of operational time per well. This represents five times improvement over the standard practice using a workover rig. The intervention was executed in several stages, according to the well intervention program, and included tubing drift and cleanout runs, retrieval, inspection, and redress of the ESP assembly, followed by its successful redeployment. The high-pressure rotary jetting tool was used to condition the wellbore tubulars across the fishing area, while downhole real-time data enabled by the 1 3/4-in. CT equipped with optical telemetry were instrumental to eliminate uncertainties associated with changing downhole conditions. The casing collar locator allowed live depth control and ensured accurate positioning of the ESP. Its careful retrieval and redeployment were monitored thanks to the downhole axial force readings, which allowed controlling the weight applied on the fishing assembly. Internal and external downhole pressure data, along with downhole temperature, helped in controlling actuation and use of the high-pressure rotary jetting nozzle under nominal conditions for maximum efficiency. This enhanced rigless ESP replacement technique, made possible by the joint use of CT and real-time downhole measurements, was confirmed as a robust workover method for retrieval and redeployment of rigless ESPs in southeast and west Kuwait. The experience gained in the first two wells brings a new level of confidence to Kuwait operators about this technique, which certainly can be expanded to other fields in the Middle East and elsewhere.
{"title":"First Retrieval and Redeployment of a Novel Rigless Electrical Submersible Pump System Via Coiled Tubing in Kuwait: A Story of Success","authors":"A. Najaf, M. Al-Haddad, A. Al-Dhafiri, Omar Al-Anezi, M. Bu-mijdad, S. Jalan, F. Snasiri, Jorge Munoz, Sarah Al Azmi, A. Salem, Ahmad Lari, E. Bespalov, Luis Gomez, N. Molero, V. Pochetnyy, Tuleen Nazzal","doi":"10.2118/207856-ms","DOIUrl":"https://doi.org/10.2118/207856-ms","url":null,"abstract":"\u0000 With the continuous production from Kuwait oil reservoirs, a clear decline in reservoir pressure is observed. Subsequently, the demand for artificial lift is increasing to sustain production. Maintenance of those wells requires frequent interventions and continuous presence of workover rigs, which affects overall cost of production. Change of the electrical submersible pump (ESP) deployment method represents one of the cost reduction initiatives undertaken by the operator to reduce well intervention time and improve asset utilization.\u0000 To minimize deferred production generated by the ESP replacement operation, a novel rigless approach leveraging coiled tubing (CT) was introduced in southeast and west Kuwait. It reduces operating costs and eliminates disruptions to operations by enabling rigless retrieval and redeployment of a standard ESP assembly. To evaluate the efficiency of using CT as rigless ESP retrieval and conveyance method, two candidate wells were selected to recover and redeploy a 108-ft-long ESP system. The intervention methodology relied on CT equipped with optical line and real-time downhole telemetry, a high-pressure rotary jetting tool, and a specific ESP deployment assembly.\u0000 The retrieval and redeployment of the ESP was executed in a single rigless intervention, averaging less than 72 hours of operational time per well. This represents five times improvement over the standard practice using a workover rig. The intervention was executed in several stages, according to the well intervention program, and included tubing drift and cleanout runs, retrieval, inspection, and redress of the ESP assembly, followed by its successful redeployment. The high-pressure rotary jetting tool was used to condition the wellbore tubulars across the fishing area, while downhole real-time data enabled by the 1 3/4-in. CT equipped with optical telemetry were instrumental to eliminate uncertainties associated with changing downhole conditions. The casing collar locator allowed live depth control and ensured accurate positioning of the ESP. Its careful retrieval and redeployment were monitored thanks to the downhole axial force readings, which allowed controlling the weight applied on the fishing assembly. Internal and external downhole pressure data, along with downhole temperature, helped in controlling actuation and use of the high-pressure rotary jetting nozzle under nominal conditions for maximum efficiency.\u0000 This enhanced rigless ESP replacement technique, made possible by the joint use of CT and real-time downhole measurements, was confirmed as a robust workover method for retrieval and redeployment of rigless ESPs in southeast and west Kuwait. The experience gained in the first two wells brings a new level of confidence to Kuwait operators about this technique, which certainly can be expanded to other fields in the Middle East and elsewhere.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75216619","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. Ragaglia, L. Napoleone, Antonio Carotenuto, Guerino De Dominicis, S. Luppina, A. Mangione, A. Faraoun, H. Mourani, Gianluca Allegretti
Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events. However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access. The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools. After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction. Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir. Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval. The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.
{"title":"Innovative Use of Wireline Tools Enables Successful Re-Entry on Subsea Wells","authors":"S. Ragaglia, L. Napoleone, Antonio Carotenuto, Guerino De Dominicis, S. Luppina, A. Mangione, A. Faraoun, H. Mourani, Gianluca Allegretti","doi":"10.2118/207442-ms","DOIUrl":"https://doi.org/10.2118/207442-ms","url":null,"abstract":"\u0000 Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events.\u0000 However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access.\u0000 The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools.\u0000 After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction.\u0000 Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir.\u0000 Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval.\u0000 The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"150 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73633179","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}
Arit Igogo, Hani El Sahn, Sara Hasrat Khan, Yatindra Bhushan, Suhaila Humaid Al Mazrooei, C. Lehmann, M. Alwahedi
Carbonate reservoir X has varying levels of maturity in terms of development. The South/West is highly matured; development activities have recently kicked-off in the Crestal part while the areas towards the Far North is not fully developed and posed the largest uncertainty in terms of reservoir quality, fluid contacts, oil saturation, well injectivity/ productivity, area potential and reserves due to poor well control. In reservoir X with segmented development areas, patches of bitumen have been found in the Far North. The extent of this Bitumen was unknown. In order to expand the CO2 development concept to achieve production target from the Far Northern flank, an understanding and mitigation of the area uncertainties is crucial. Reservoir bitumen is a highly viscous, asphaltene rich hydrocarbon that affects reservoir performance. Distinguishing between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity and density contrast between the reservoir bitumen and light oil makes it difficult, if not impossible, to make such differentiation using only conventional logs such as neutron, density, and resistivity. This paper highlights the utilization and integration of advanced logging tools such as nuclear magnetic resonance and dielectric, in conjunction with routine logs, pressure points, RCI samples, vertical interference test and core data to differentiate between reservoir bitumen and other hydrocarbon types in the pore space. The major findings from the studies shows bitumen doesn't form as a single layer but occurs in different subzones as patches which is a challenge for static modelling. When high molecular weight hydrocarbons are distributed in the pore space and coexist with light and producible hydrocarbons, reservoir bitumen is likely to block pore throats. The Bitumen present in this reservoir have a log response similar to conventional pore fluids. The outcome of this study has helped in refining the bitumen boundary, optimize well placement, resolved the uncertainties associated with deeper fluid contacts and provided realistic estimate of STOIIP.
{"title":"Identification of Patches of Bitumen in a Carbonate Reservoir: A Case Study","authors":"Arit Igogo, Hani El Sahn, Sara Hasrat Khan, Yatindra Bhushan, Suhaila Humaid Al Mazrooei, C. Lehmann, M. Alwahedi","doi":"10.2118/208058-ms","DOIUrl":"https://doi.org/10.2118/208058-ms","url":null,"abstract":"\u0000 Carbonate reservoir X has varying levels of maturity in terms of development. The South/West is highly matured; development activities have recently kicked-off in the Crestal part while the areas towards the Far North is not fully developed and posed the largest uncertainty in terms of reservoir quality, fluid contacts, oil saturation, well injectivity/ productivity, area potential and reserves due to poor well control. In reservoir X with segmented development areas, patches of bitumen have been found in the Far North. The extent of this Bitumen was unknown. In order to expand the CO2 development concept to achieve production target from the Far Northern flank, an understanding and mitigation of the area uncertainties is crucial.\u0000 Reservoir bitumen is a highly viscous, asphaltene rich hydrocarbon that affects reservoir performance. Distinguishing between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity and density contrast between the reservoir bitumen and light oil makes it difficult, if not impossible, to make such differentiation using only conventional logs such as neutron, density, and resistivity.\u0000 This paper highlights the utilization and integration of advanced logging tools such as nuclear magnetic resonance and dielectric, in conjunction with routine logs, pressure points, RCI samples, vertical interference test and core data to differentiate between reservoir bitumen and other hydrocarbon types in the pore space.\u0000 The major findings from the studies shows bitumen doesn't form as a single layer but occurs in different subzones as patches which is a challenge for static modelling. When high molecular weight hydrocarbons are distributed in the pore space and coexist with light and producible hydrocarbons, reservoir bitumen is likely to block pore throats. The Bitumen present in this reservoir have a log response similar to conventional pore fluids.\u0000 The outcome of this study has helped in refining the bitumen boundary, optimize well placement, resolved the uncertainties associated with deeper fluid contacts and provided realistic estimate of STOIIP.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"461 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77517964","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：