Effective project management plays a crucial role to the success of organizations via resilient execution of activities, in terms of performance and efficiency. Due to the recent market dynamics and its associated uncertainties, affecting several segments in the oil and gas (O&G) industry, utilization of innovative contracting schemes such as Front End Engineering Design (FEED) competition, and value engineered products are becoming of great importance to achieve the project's goals optimally. This paper discusses the competitiveness and strategic benefits of employing the vendor's pre-engineered and standardized turbomachinery equipment/solutions, to meet the required functionality while maintaining the highest levels of quality and safety. Several project management concepts and tools were employed, such as SWOT analysis, to discuss the benefits of supplying vendor's pre-engineered high value and long-lead turbomachinery equipment within projects, as a cost-effective solution, in place of customized products. A Requirements-to-Implementation Mapping (RIM) exercise was also carried out to benchmark the pre-engineered solutions with the industry practices while considering the packaging requirements from well-known international and national oil companies. This paper also presents success stories of implementing pre-engineered solutions that strongly contributed in improving the management of projects from engineering to operational phase. This study works in line with the recent O&G operators’ initiatives in promoting agile approach to mitigate the forces that are impacting the industry and in turn the economy, such as COVID-19 pandemic. The study analysis, employing semi-quantitative approach, revealed that the pre-engineered solution brings to customers an improved value proposition in terms of cost, delivery, quality, safety, and aftermarket support, which contributes greatly in minimizing gold plating to achieve leaner projects. Standardized equipment is also found to be effective in minimizing the risks associated with changes and therefore improving the control on project constraints as well as simplifying the purchasing management of strategic equipment. In this respect, the use of standardization and pre-engineered activities could lead to a reduction of lead time up to 30%. The reliability of the standardized equipment will also be increased due to the proven frozen designs which have been repeatedly manufactured, tested, and supplied and therefore ensures successful and seamless project close-out. The proposed approach of mixing pre-engineered commodities to customized and configurable features based on site conditions provides the proper flexibility required by O&G industry while, simultaneously, maximizing the benefits of standardization. The strategic benefits of pre-engineered turbomachinery packages in the context of project management and supply chain process is not well recognized. This study explains these benefits to incr
{"title":"Pre-Engineered Standardized Turbomachinery Solutions: A Strategic Approach to Lean Project Management","authors":"A. Khalaf, Maher Ayed, Gianni Acquisti, E. Rizzo","doi":"10.2118/207304-ms","DOIUrl":"https://doi.org/10.2118/207304-ms","url":null,"abstract":"\u0000 Effective project management plays a crucial role to the success of organizations via resilient execution of activities, in terms of performance and efficiency. Due to the recent market dynamics and its associated uncertainties, affecting several segments in the oil and gas (O&G) industry, utilization of innovative contracting schemes such as Front End Engineering Design (FEED) competition, and value engineered products are becoming of great importance to achieve the project's goals optimally. This paper discusses the competitiveness and strategic benefits of employing the vendor's pre-engineered and standardized turbomachinery equipment/solutions, to meet the required functionality while maintaining the highest levels of quality and safety.\u0000 Several project management concepts and tools were employed, such as SWOT analysis, to discuss the benefits of supplying vendor's pre-engineered high value and long-lead turbomachinery equipment within projects, as a cost-effective solution, in place of customized products. A Requirements-to-Implementation Mapping (RIM) exercise was also carried out to benchmark the pre-engineered solutions with the industry practices while considering the packaging requirements from well-known international and national oil companies. This paper also presents success stories of implementing pre-engineered solutions that strongly contributed in improving the management of projects from engineering to operational phase. This study works in line with the recent O&G operators’ initiatives in promoting agile approach to mitigate the forces that are impacting the industry and in turn the economy, such as COVID-19 pandemic.\u0000 The study analysis, employing semi-quantitative approach, revealed that the pre-engineered solution brings to customers an improved value proposition in terms of cost, delivery, quality, safety, and aftermarket support, which contributes greatly in minimizing gold plating to achieve leaner projects. Standardized equipment is also found to be effective in minimizing the risks associated with changes and therefore improving the control on project constraints as well as simplifying the purchasing management of strategic equipment. In this respect, the use of standardization and pre-engineered activities could lead to a reduction of lead time up to 30%. The reliability of the standardized equipment will also be increased due to the proven frozen designs which have been repeatedly manufactured, tested, and supplied and therefore ensures successful and seamless project close-out. The proposed approach of mixing pre-engineered commodities to customized and configurable features based on site conditions provides the proper flexibility required by O&G industry while, simultaneously, maximizing the benefits of standardization.\u0000 The strategic benefits of pre-engineered turbomachinery packages in the context of project management and supply chain process is not well recognized. This study explains these benefits to incr","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72805025","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}
Aditya Ojha, M. A. Al Hosani, A. A. Al Bairaq, S. Mengal, I. Mohamed, A. Abdullayev, Allen Roopal
This paper presents modeling a novel approach to determine the impact of implementing smart completions on water injectors located near the periphery of the gas cap and on gas producing wells situated in the gas cap of a giant Middle East onshore field. The objective of the study is to thoroughly investigate different smart completion designs which can effectively delay water breakthrough on the gas cap wells. The study investigates the impact of adding smart well completion designs like ICD and AICD valves in delaying water breakthrough. The first phase involves adding smart completions to only water injectors. Sensitivity runs on several downhole completion design scenarios are conducted using a commercial near wellbore simulator and the optimal downhole completion design is implemented on a dynamic model and its impact is examined using a reservoir simulator. In the second phase, this approach is applied only for gas producers, and in the third phase the smart completions are simultaneously applied to both water injectors and gas producers. The detailed study has revealed that the uncertainties and time involved in selecting optimal ICD design and placements could be reduced considerably by using an optimized workflow. The workflow uses a carefully designed process of using the outcomes from near wellbore simulators and incorporating the results in the actual full field dynamic models to assess the field level impacts. When compared to the bare foot design, ICD and AICD valves showed better performance in delaying water breakthrough from the gas wells. This paper provides a detailed study on the impact of different smart completions on delaying water breakthrough in gas production wells. The study also investigates how a uniform injection or production profile can be produced using different smart completions. Uniform injection and production profiles limit water fingering in the reservoir, and thereby delay water breakthrough caused by the flow of water through high permeability channels.
{"title":"Modeling a Novel Approach to Delay the Water Breakthrough in Gas Cap Wells Using Smart Completions: Case Study Onshore Abu Dhabi Field","authors":"Aditya Ojha, M. A. Al Hosani, A. A. Al Bairaq, S. Mengal, I. Mohamed, A. Abdullayev, Allen Roopal","doi":"10.2118/207862-ms","DOIUrl":"https://doi.org/10.2118/207862-ms","url":null,"abstract":"\u0000 This paper presents modeling a novel approach to determine the impact of implementing smart completions on water injectors located near the periphery of the gas cap and on gas producing wells situated in the gas cap of a giant Middle East onshore field. The objective of the study is to thoroughly investigate different smart completion designs which can effectively delay water breakthrough on the gas cap wells.\u0000 The study investigates the impact of adding smart well completion designs like ICD and AICD valves in delaying water breakthrough. The first phase involves adding smart completions to only water injectors. Sensitivity runs on several downhole completion design scenarios are conducted using a commercial near wellbore simulator and the optimal downhole completion design is implemented on a dynamic model and its impact is examined using a reservoir simulator. In the second phase, this approach is applied only for gas producers, and in the third phase the smart completions are simultaneously applied to both water injectors and gas producers.\u0000 The detailed study has revealed that the uncertainties and time involved in selecting optimal ICD design and placements could be reduced considerably by using an optimized workflow. The workflow uses a carefully designed process of using the outcomes from near wellbore simulators and incorporating the results in the actual full field dynamic models to assess the field level impacts.\u0000 When compared to the bare foot design, ICD and AICD valves showed better performance in delaying water breakthrough from the gas wells.\u0000 This paper provides a detailed study on the impact of different smart completions on delaying water breakthrough in gas production wells. The study also investigates how a uniform injection or production profile can be produced using different smart completions. Uniform injection and production profiles limit water fingering in the reservoir, and thereby delay water breakthrough caused by the flow of water through high permeability channels.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72982229","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}
R. Jeughale, K. Andrews, S. A. Al Ali, T. Toki, Hisaya Tanaka, Ryosuke Sato, J. Luzardo, G. Sarap, Saumit Chatterjee, Z. Meki
Drilling and completion operations in depleted reservoirs, are challenging due to narrow margin between pore and fracture pressures. Therefore, Ultra-Low Density Reservoir Drilling Fluid (RDF) with optimum parameters is required to drill these wells safely. Design and effective field application of a sound engineered fluid solution to fulfill these operational demands are described. Ultra-Low Density RDF NAF with minimal fluid invasion characteristics was developed after extensive lab testing, to cover the fluid density from 7.2 – 8.0 ppg. The fluid properties were optimized based on reservoir requirements and challenging bottom-hole conditions. The design criteria benchmarks and field application details are presented. Fluids were stress tested for drill solids, reservoir water and density increase contamination. Multi-segment collaboration and teamwork were key during job planning and on-site job execution, to achieve operational success. For the first time in UAE, a major Offshore Operator successfully applied an Ultra-Low Density RDF-NAF, which provided remarkable stability and performance. The fluid was tested in the lab with polymeric viscosifier alone and in combination with organophilic clay. In order to gain rheology during the initial mixing, about 3.0 ppb of organophilic clay were introduced to system along with the polymeric viscosifier. Later, all the new fluid batches were built with polymeric additives alone to achieve target properties. A total of 10,250 ft of 8 ½" horizontal section was drilled to section TD with record ROP compared to previous wells in the same field, with no fluids related complications. With limited support from the solid control equipment, the team managed to keep the density ranging from 7.5 ppg to 7.8 ppg at surface condition, using premixed dilution. Bridging was monitored through actual testing on location and successfully maintained the target PSD values throughout the section by splitting the flow on three shaker screen size combination. Due to non-operation related issues, hole was kept static for 20 days. After such long static time, 8 ½" drilling BHA was run to bottom smoothly precautionary breaking circulation every 5 stands. Finally, after successful logging operation, 6 5/8" LEL liner was set to TD and the well completed as planned. Success of this field application indicates that an Ultra-Low density fluid can be designed, run successfully and deliver exemplary performance. Lessons learned are compared with conceptual design for future optimization. Laboratory test results are presented, which formed the basis of a seamless planned field application.
{"title":"Development and First Application of an Ultra-Low Density Non-Aqueous Reservoir Drilling Fluid in the United Arab Emirates: A Viable Technical Solution to Drill Maximum Reservoir Contact Wells Across Depleted Reservoirs","authors":"R. Jeughale, K. Andrews, S. A. Al Ali, T. Toki, Hisaya Tanaka, Ryosuke Sato, J. Luzardo, G. Sarap, Saumit Chatterjee, Z. Meki","doi":"10.2118/207257-ms","DOIUrl":"https://doi.org/10.2118/207257-ms","url":null,"abstract":"\u0000 Drilling and completion operations in depleted reservoirs, are challenging due to narrow margin between pore and fracture pressures. Therefore, Ultra-Low Density Reservoir Drilling Fluid (RDF) with optimum parameters is required to drill these wells safely. Design and effective field application of a sound engineered fluid solution to fulfill these operational demands are described.\u0000 Ultra-Low Density RDF NAF with minimal fluid invasion characteristics was developed after extensive lab testing, to cover the fluid density from 7.2 – 8.0 ppg. The fluid properties were optimized based on reservoir requirements and challenging bottom-hole conditions. The design criteria benchmarks and field application details are presented. Fluids were stress tested for drill solids, reservoir water and density increase contamination. Multi-segment collaboration and teamwork were key during job planning and on-site job execution, to achieve operational success.\u0000 For the first time in UAE, a major Offshore Operator successfully applied an Ultra-Low Density RDF-NAF, which provided remarkable stability and performance. The fluid was tested in the lab with polymeric viscosifier alone and in combination with organophilic clay. In order to gain rheology during the initial mixing, about 3.0 ppb of organophilic clay were introduced to system along with the polymeric viscosifier. Later, all the new fluid batches were built with polymeric additives alone to achieve target properties. A total of 10,250 ft of 8 ½\" horizontal section was drilled to section TD with record ROP compared to previous wells in the same field, with no fluids related complications. With limited support from the solid control equipment, the team managed to keep the density ranging from 7.5 ppg to 7.8 ppg at surface condition, using premixed dilution.\u0000 Bridging was monitored through actual testing on location and successfully maintained the target PSD values throughout the section by splitting the flow on three shaker screen size combination. Due to non-operation related issues, hole was kept static for 20 days. After such long static time, 8 ½\" drilling BHA was run to bottom smoothly precautionary breaking circulation every 5 stands. Finally, after successful logging operation, 6 5/8\" LEL liner was set to TD and the well completed as planned.\u0000 Success of this field application indicates that an Ultra-Low density fluid can be designed, run successfully and deliver exemplary performance. Lessons learned are compared with conceptual design for future optimization. Laboratory test results are presented, which formed the basis of a seamless planned field application.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78930264","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 discusses how the application of large, gas turbine-based power blocks (>50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows: – Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads. The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.
{"title":"Evaluating Small vs. Large Power Blocks for Pipeline Compression Stations","authors":"Gautam Chhibber, Mayank Kumar Dave","doi":"10.2118/207479-ms","DOIUrl":"https://doi.org/10.2118/207479-ms","url":null,"abstract":"\u0000 This paper discusses how the application of large, gas turbine-based power blocks (>50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows:\u0000 – Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads.\u0000 The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77989103","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. A. Al Mesaabi, G. Cambois, J. Cowell, D. Arnold, Mohamed Fawzi Boukhanfra, Saeed Hamad Al Karbi, M. Mahgoub, Khalid Obaid
In 2017 ADNOC decided to cover the entire Abu Dhabi Emirate, onshore and offshore, with high- resolution and high-fold 3D seismic. Acquisition of the world's largest continuous seismic survey started in late 2018 and is around 77% complete at the time of writing. Data processing is well under way and interpretation of the first delivered 3D cubes is ongoing. Now is an opportune time to review the status of this gigantic project and draw preliminary lessons. Comparison with legacy data shows a massive improvement in deep imaging, which was one of the main objectives of this survey. The basement can clearly be interpreted, while it is hardly visible on legacy data being covered with high energy multiples. A thorough analysis demonstrated that increased offset is the main reason for the uplift. The large fold and the low frequency sweep also help recover signal down to 3 Hz. This extends the bandwidth in the low frequencies by one to two octaves compared to legacy data, which tremendously benefits structural interpretation and stratigraphic inversion.
{"title":"Lessons Learned From the World's Largest Continuous Onshore and Offshore 3D Seismic Survey","authors":"S. A. Al Mesaabi, G. Cambois, J. Cowell, D. Arnold, Mohamed Fawzi Boukhanfra, Saeed Hamad Al Karbi, M. Mahgoub, Khalid Obaid","doi":"10.2118/208009-ms","DOIUrl":"https://doi.org/10.2118/208009-ms","url":null,"abstract":"\u0000 In 2017 ADNOC decided to cover the entire Abu Dhabi Emirate, onshore and offshore, with high- resolution and high-fold 3D seismic. Acquisition of the world's largest continuous seismic survey started in late 2018 and is around 77% complete at the time of writing. Data processing is well under way and interpretation of the first delivered 3D cubes is ongoing. Now is an opportune time to review the status of this gigantic project and draw preliminary lessons.\u0000 Comparison with legacy data shows a massive improvement in deep imaging, which was one of the main objectives of this survey. The basement can clearly be interpreted, while it is hardly visible on legacy data being covered with high energy multiples. A thorough analysis demonstrated that increased offset is the main reason for the uplift. The large fold and the low frequency sweep also help recover signal down to 3 Hz. This extends the bandwidth in the low frequencies by one to two octaves compared to legacy data, which tremendously benefits structural interpretation and stratigraphic inversion.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77162715","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 economic success of unconventional reservoirs relies on driving down completion costs. Manually measuring the operational efficiency for a multi-well pad can be error-prone and time-prohibitive. Complete automation of this analysis can provide an effortless real-time insight to completion engineers. This study presents a real-time method for measuring the time spent on each completion activity, thereby enabling the identification and potential cost reduction avenues. Two data acquisition boxes are utilized at the completion site to transmit both the fracturing and wireline data in real-time to a cloud server. A data processing algorithm is described to determine the start and end of these two operations for each stage of every well on the pad. The described method then determines other activity intervals (fracturing swap-over, wireline swap-over, and waiting on offset wells) based on the relationship between the fracturing and wireline segments of all the wells. The processed data results can be viewed in real-time on mobile or computers connected to the cloud. Viewing the full operational time log in real-time helps engineers analyze the whole operation and determine key performance indicators (KPIs) such as the number of fractured stages per day, pumping percentage, average fracture, and wireline swap-over durations for a given time period. In addition, the performance of the day and night crews can be evaluated. By plotting a comparison of KPIs for wireline and fracturing times, trends can be readily identified for improving operational efficiency. Practices from best-performing stages can be adopted to reduce non-pumping times. This helps operators save time and money to optimize for more efficient operations. As the number of wells increases, the complexity of manual generation of time-log increases. The presented method can handle multi-well fracturing and wireline operations without such difficulty and in real-time. A case study is also presented, where an operator in the US Permian basin used this method in real-time to view and optimize zipper operations. Analysis indicated that the time spent on the swap over activities could be reduced. This operator set a realistic goal of reducing 10 minutes per swap-over interval. Within one pad, the goal was reached utilizing this method, resulting in reducing 15 hours from the total pad time. The presented method provides an automated overview of fracturing operations. Based on the analysis, timely decisions can be made to reduce operational costs. Moreover, because this method is automated, it is not limited to single well operations but can handle multi-well pad completion designs that are commonplace in unconventionals.
{"title":"Improving Operational Efficiency Using Automated Time Analysis for Multi-Well Pad Fracturing","authors":"F. Siddiqui, M. Kamyab, M. Lowder","doi":"10.2118/207318-ms","DOIUrl":"https://doi.org/10.2118/207318-ms","url":null,"abstract":"\u0000 The economic success of unconventional reservoirs relies on driving down completion costs. Manually measuring the operational efficiency for a multi-well pad can be error-prone and time-prohibitive. Complete automation of this analysis can provide an effortless real-time insight to completion engineers. This study presents a real-time method for measuring the time spent on each completion activity, thereby enabling the identification and potential cost reduction avenues.\u0000 Two data acquisition boxes are utilized at the completion site to transmit both the fracturing and wireline data in real-time to a cloud server. A data processing algorithm is described to determine the start and end of these two operations for each stage of every well on the pad. The described method then determines other activity intervals (fracturing swap-over, wireline swap-over, and waiting on offset wells) based on the relationship between the fracturing and wireline segments of all the wells. The processed data results can be viewed in real-time on mobile or computers connected to the cloud.\u0000 Viewing the full operational time log in real-time helps engineers analyze the whole operation and determine key performance indicators (KPIs) such as the number of fractured stages per day, pumping percentage, average fracture, and wireline swap-over durations for a given time period. In addition, the performance of the day and night crews can be evaluated.\u0000 By plotting a comparison of KPIs for wireline and fracturing times, trends can be readily identified for improving operational efficiency. Practices from best-performing stages can be adopted to reduce non-pumping times. This helps operators save time and money to optimize for more efficient operations. As the number of wells increases, the complexity of manual generation of time-log increases. The presented method can handle multi-well fracturing and wireline operations without such difficulty and in real-time.\u0000 A case study is also presented, where an operator in the US Permian basin used this method in real-time to view and optimize zipper operations. Analysis indicated that the time spent on the swap over activities could be reduced. This operator set a realistic goal of reducing 10 minutes per swap-over interval. Within one pad, the goal was reached utilizing this method, resulting in reducing 15 hours from the total pad time.\u0000 The presented method provides an automated overview of fracturing operations. Based on the analysis, timely decisions can be made to reduce operational costs. Moreover, because this method is automated, it is not limited to single well operations but can handle multi-well pad completion designs that are commonplace in unconventionals.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74013388","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}
Yuanjun Li, R. Horne, A. Al Shmakhy, Tania Felix Menchaca
The problem of missing data is a frequent occurrence in well production history records. Due to network outage, facility maintenance or equipment failure, the time series production data measured from surface and downhole gauges can be intermittent. The fragmentary data are an obstacle for reservoir management. The incomplete dataset is commonly simplified by omitting all observations with missing values, which will lead to significant information loss. Thus, to fill the missing data gaps, in this study, we developed and tested several missing data imputation approaches using machine learning and deep learning methods. Traditional data imputation methods such as interpolation and counting most frequent values can introduce bias to the data as the correlations between features are not considered. Thus, in this study, we investigated several multivariate imputation algorithms that use the entire set of available data streams to estimate the missing values. The methods use a full suite of well measurements, including wellhead and downhole pressures, oil, water and gas flow rates, surface and downhole temperatures, choke settings, etc. Any parameter that has gaps in its recorded history can be imputed from the other available data streams. The models were tested on both synthetic and real datasets from operating Norwegian and Abu Dhabi reservoirs. Based on the characteristics of the field data, we introduced different types of continuous missing distributions, which are the combinations of single-multiple missing sections in a long-short time span, to the complete dataset. We observed that as the missing time span expands, the stability of the more successful methods can be kept to a threshold of 30% of the entire dataset. In addition, for a single missing section over a shorter period, which could represent a weather perturbation, most methods we tried were able to achieve high imputation accuracy. In the case of multiple missing sections over a longer time span, which is typical of gauge failures, other methods were better candidates to capture the overall correlation in the multivariate dataset. Most missing data problems addressed in our industry focus on single feature imputation. In this study, we developed an efficient procedure that enables fast reconstruction of the entire production dataset with multiple missing sections in different variables. Ultimately, the complete information can support the reservoir history matching process, production allocation, and develop models for reservoir performance prediction.
{"title":"Reconstruction of Missing Segments in Well Data History Using Data Analytics","authors":"Yuanjun Li, R. Horne, A. Al Shmakhy, Tania Felix Menchaca","doi":"10.2118/208137-ms","DOIUrl":"https://doi.org/10.2118/208137-ms","url":null,"abstract":"\u0000 The problem of missing data is a frequent occurrence in well production history records. Due to network outage, facility maintenance or equipment failure, the time series production data measured from surface and downhole gauges can be intermittent. The fragmentary data are an obstacle for reservoir management. The incomplete dataset is commonly simplified by omitting all observations with missing values, which will lead to significant information loss. Thus, to fill the missing data gaps, in this study, we developed and tested several missing data imputation approaches using machine learning and deep learning methods.\u0000 Traditional data imputation methods such as interpolation and counting most frequent values can introduce bias to the data as the correlations between features are not considered. Thus, in this study, we investigated several multivariate imputation algorithms that use the entire set of available data streams to estimate the missing values. The methods use a full suite of well measurements, including wellhead and downhole pressures, oil, water and gas flow rates, surface and downhole temperatures, choke settings, etc. Any parameter that has gaps in its recorded history can be imputed from the other available data streams.\u0000 The models were tested on both synthetic and real datasets from operating Norwegian and Abu Dhabi reservoirs. Based on the characteristics of the field data, we introduced different types of continuous missing distributions, which are the combinations of single-multiple missing sections in a long-short time span, to the complete dataset. We observed that as the missing time span expands, the stability of the more successful methods can be kept to a threshold of 30% of the entire dataset. In addition, for a single missing section over a shorter period, which could represent a weather perturbation, most methods we tried were able to achieve high imputation accuracy. In the case of multiple missing sections over a longer time span, which is typical of gauge failures, other methods were better candidates to capture the overall correlation in the multivariate dataset.\u0000 Most missing data problems addressed in our industry focus on single feature imputation. In this study, we developed an efficient procedure that enables fast reconstruction of the entire production dataset with multiple missing sections in different variables. Ultimately, the complete information can support the reservoir history matching process, production allocation, and develop models for reservoir performance prediction.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75274322","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}
Mattia Paolo Bergamini, M. Chiavico, L. Bracco, A. Moglia, M. Buffagni
The Water Balance Assessment is a methodological approach developed and applied by Eni for the identification of improvements in water management at site level. The approach is based on three steps. The following report describes each step and the application of the approach to a real case study in Tunisia. Water is a vital resource for our planet and for humankind. Biodiversity and ecosystems’ preservation, human health, and food security as well as energy production, industrial development and economic growth are all dependent on water. The consequences of climate change and the actual projections of increasing water demand will affect water availability and quality in the coming years. About the Oil & Gas sector, this industry consumes and produces significant volumes of water. For this reason, energy companies must consider sustainable options for the use of this resource, especially in water stress areas. This can be achieved through:A deep knowledge of the site water streams and of the context where the site is located.Identification of improvements and initiatives that could reduce the water risk of the site. About water safeguarding, Eni is committed to pursue the following practices:Water Conservation: Upstream Oil & Gas operations need significant quantities of water; a key element for its conservation includes the reduction of withdrawals and the efficiency in water use.Water Reuse and Valorization: Upstream Oil & Gas operations must manage large volumes of wastewater, mainly Produced Water. Design solutions shall introduce and maximize the recycle of water with the adoption of suitable treatments, to make discharges compatible with the reuse in the same production cycle or by third parties (e.g., other plants, local communities), and pursue the opportunity to reuse industrial water, instead of discharging it as wastewater. For their deployment, Eni has defined and applied a methodological approach to support the definition of improvement and optimization initiatives of water management at the site level. The approach represents an application of a "convergence approach" which, starting from an overall view of the site, identifies opportunities, further and more detailed areas of analysis, and design projects that can improve water use, management, and reuse. The methodological approach is based on the following steps:A country-based framework study on water resources, and water-related risks analysis at country and local level.A Water Balance Assessment, gathering water qualitative and quantitative information and site framework details.Definition of site initiatives for wastewater reuse and valorization, and for the optimization of water withdrawals, based on the above steps and considering local legislation. Through this approach, operational water risks exposure is analyzed in detail, allowing to address a wide range of opportunities for the improvement of water management, also through the development of new synergies with
{"title":"Water Balance Assessment for Water Management in Oil & Gas Operations: A Methodological Approach","authors":"Mattia Paolo Bergamini, M. Chiavico, L. Bracco, A. Moglia, M. Buffagni","doi":"10.2118/207448-ms","DOIUrl":"https://doi.org/10.2118/207448-ms","url":null,"abstract":"\u0000 The Water Balance Assessment is a methodological approach developed and applied by Eni for the identification of improvements in water management at site level. The approach is based on three steps. The following report describes each step and the application of the approach to a real case study in Tunisia.\u0000 Water is a vital resource for our planet and for humankind. Biodiversity and ecosystems’ preservation, human health, and food security as well as energy production, industrial development and economic growth are all dependent on water. The consequences of climate change and the actual projections of increasing water demand will affect water availability and quality in the coming years. About the Oil & Gas sector, this industry consumes and produces significant volumes of water. For this reason, energy companies must consider sustainable options for the use of this resource, especially in water stress areas. This can be achieved through:A deep knowledge of the site water streams and of the context where the site is located.Identification of improvements and initiatives that could reduce the water risk of the site.\u0000 About water safeguarding, Eni is committed to pursue the following practices:Water Conservation: Upstream Oil & Gas operations need significant quantities of water; a key element for its conservation includes the reduction of withdrawals and the efficiency in water use.Water Reuse and Valorization: Upstream Oil & Gas operations must manage large volumes of wastewater, mainly Produced Water. Design solutions shall introduce and maximize the recycle of water with the adoption of suitable treatments, to make discharges compatible with the reuse in the same production cycle or by third parties (e.g., other plants, local communities), and pursue the opportunity to reuse industrial water, instead of discharging it as wastewater.\u0000 For their deployment, Eni has defined and applied a methodological approach to support the definition of improvement and optimization initiatives of water management at the site level. The approach represents an application of a \"convergence approach\" which, starting from an overall view of the site, identifies opportunities, further and more detailed areas of analysis, and design projects that can improve water use, management, and reuse.\u0000 The methodological approach is based on the following steps:A country-based framework study on water resources, and water-related risks analysis at country and local level.A Water Balance Assessment, gathering water qualitative and quantitative information and site framework details.Definition of site initiatives for wastewater reuse and valorization, and for the optimization of water withdrawals, based on the above steps and considering local legislation.\u0000 Through this approach, operational water risks exposure is analyzed in detail, allowing to address a wide range of opportunities for the improvement of water management, also through the development of new synergies with ","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74609067","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}
In recent years, the global buckling assessment of offshore pipelines in High Pressure-High Temperature (HPHT) condition become increasingly challenging since more complex pipeline system arrangement e.g. pipe(s) or cable(s) is strapped onto a larger pipeline, are rapidly utilized in many areas. Yet, the detailed guideline to assess the buckle of bundles remains unclear, therefore this study will focus to investigate on a methodical and reproducible approach to analyze in-service buckling behavior of bundled offshore pipeline system. The global buckling behavior of bundled offshore pipeline system in this study is investigated using commercial Finite Element (FE) software. Two carbon steel pipelines with different diameter are bundled and the buckling behavior is studied under the influence of buckle triggers. In the actual condition, the rogue buckle trigger is generated from OOS (out of straightness) or imperfection e.g. due to laying tolerance. Varying dimension parameter such as diameter ratio between the main pipeline and strapped pipeline are considered to understand the impact of this parameter on the buckle behavior. The study begins with a comparison of the results using numerical and analytical approaches on a straight pipeline in an unbuckled condition for validation purposes. The design parameters including wall thickness, process data, and pipe-soil interaction data, are varied since it influences the buckle behavior. In addition, some design parameter such as material properties and pipeline length will be adopted from a typical offshore pipeline project and the values are fixed so the exercise can focus on the most governing parameters. Following this, two numerical modelling methods, the equivalent properties method and the connector method, are presented in this study to simulate bundled systems. With a good agreement between the analytical and numerical approach, some buckle trigger is introduced on the numerical model of the bundled pipeline so the system is able to buckle and the behavior can be evaluated further. The strain level, lateral displacement, axial feed-in and pipe integrity shall be reported in the post-buckle conditions for both main pipe and strapped pipe as per current code and standard requirement. With more reliable results of buckling assessment for bundled pipeline system, it gives technical confidence and a major saving in both Capital Expenditure (CAPEX) and Operational Expenditure (OPEX). Industry has put serious effort through various Joint Industry Projects (JIP) to develop the global buckling assessment guideline in order to ensure long term integrity operation. Although the JIP guideline is predominantly for single pipeline system, similar assessment is demanded also for bundled pipeline system which described in this study. Key findings of the assessment are presented along with an overview of the design process and the typical mitigation techniques to be considered for similar subsea pipeline proj
{"title":"Global Buckling Characteristics of Offshore Bundled Pipeline System","authors":"D. Yurindatama, Nawin Singh, Vinod Pillai","doi":"10.2118/207223-ms","DOIUrl":"https://doi.org/10.2118/207223-ms","url":null,"abstract":"\u0000 In recent years, the global buckling assessment of offshore pipelines in High Pressure-High Temperature (HPHT) condition become increasingly challenging since more complex pipeline system arrangement e.g. pipe(s) or cable(s) is strapped onto a larger pipeline, are rapidly utilized in many areas. Yet, the detailed guideline to assess the buckle of bundles remains unclear, therefore this study will focus to investigate on a methodical and reproducible approach to analyze in-service buckling behavior of bundled offshore pipeline system. The global buckling behavior of bundled offshore pipeline system in this study is investigated using commercial Finite Element (FE) software. Two carbon steel pipelines with different diameter are bundled and the buckling behavior is studied under the influence of buckle triggers. In the actual condition, the rogue buckle trigger is generated from OOS (out of straightness) or imperfection e.g. due to laying tolerance. Varying dimension parameter such as diameter ratio between the main pipeline and strapped pipeline are considered to understand the impact of this parameter on the buckle behavior. The study begins with a comparison of the results using numerical and analytical approaches on a straight pipeline in an unbuckled condition for validation purposes. The design parameters including wall thickness, process data, and pipe-soil interaction data, are varied since it influences the buckle behavior. In addition, some design parameter such as material properties and pipeline length will be adopted from a typical offshore pipeline project and the values are fixed so the exercise can focus on the most governing parameters. Following this, two numerical modelling methods, the equivalent properties method and the connector method, are presented in this study to simulate bundled systems. With a good agreement between the analytical and numerical approach, some buckle trigger is introduced on the numerical model of the bundled pipeline so the system is able to buckle and the behavior can be evaluated further. The strain level, lateral displacement, axial feed-in and pipe integrity shall be reported in the post-buckle conditions for both main pipe and strapped pipe as per current code and standard requirement. With more reliable results of buckling assessment for bundled pipeline system, it gives technical confidence and a major saving in both Capital Expenditure (CAPEX) and Operational Expenditure (OPEX). Industry has put serious effort through various Joint Industry Projects (JIP) to develop the global buckling assessment guideline in order to ensure long term integrity operation. Although the JIP guideline is predominantly for single pipeline system, similar assessment is demanded also for bundled pipeline system which described in this study. Key findings of the assessment are presented along with an overview of the design process and the typical mitigation techniques to be considered for similar subsea pipeline proj","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76375096","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. Ogienagbon, M. Khalifeh, Xinxiang Yang, E. Kuru
Formation of microannuli at the interface of cement-casing can create well integrity issues. X-ray CT and Optical microscopy are technological trends that may have potential for direct visualization of microannuli. CT has an advantage of providing non-destructive visualization of microannuli, but its resolution suffers with increase in casing thickness. Conversely, Optical microscopy has the potential of providing higher resolution needed to detect smaller sized microannuli; however, information about microannuli is limited to only a few sections where samples have been sliced. The objective of the current article is to describe a methodology to examine the interface of cement-casing. Experimental work was combined with literature review. This includes both direct visualization methods, evaluation of current trends to better understand the characteristics and geometric variation of relevant leakage paths. We generate test specimens consisting of cement plugs, various steel casing thickness and nano-coated aluminium casings. Hydraulic sealability tests were conducted by injecting water at the cement-casing interface. Flow rates are then interpreted in terms of microannuli aperture and direct visualization of the cement plug-casing interface by CT and Optical microscopy was implemented. The experimental findings of this article will form a basis for studying geometry and size of microannuli as well as modelling of fluid migration.
{"title":"Manuscript Title: Characterization of Microannuli at the Cement-Casing Interface: Development of Methodology","authors":"A. Ogienagbon, M. Khalifeh, Xinxiang Yang, E. Kuru","doi":"10.2118/207581-ms","DOIUrl":"https://doi.org/10.2118/207581-ms","url":null,"abstract":"\u0000 Formation of microannuli at the interface of cement-casing can create well integrity issues. X-ray CT and Optical microscopy are technological trends that may have potential for direct visualization of microannuli. CT has an advantage of providing non-destructive visualization of microannuli, but its resolution suffers with increase in casing thickness. Conversely, Optical microscopy has the potential of providing higher resolution needed to detect smaller sized microannuli; however, information about microannuli is limited to only a few sections where samples have been sliced. The objective of the current article is to describe a methodology to examine the interface of cement-casing. Experimental work was combined with literature review. This includes both direct visualization methods, evaluation of current trends to better understand the characteristics and geometric variation of relevant leakage paths. We generate test specimens consisting of cement plugs, various steel casing thickness and nano-coated aluminium casings. Hydraulic sealability tests were conducted by injecting water at the cement-casing interface. Flow rates are then interpreted in terms of microannuli aperture and direct visualization of the cement plug-casing interface by CT and Optical microscopy was implemented. The experimental findings of this article will form a basis for studying geometry and size of microannuli as well as modelling of fluid migration.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83468271","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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