Ahmed. N. Alduaij, Z. Al-Bensaad, D. Ahmed, M. Noor, Nabil Batita, AbdulMuqtadir Khan
An openhole multistage completion required selective fracture stimulation, flow control, and sand control in each zone. An openhole multistage completion was designed by combining a production sleeve integrated with sand screens and inflow control devices and a fracture sleeve with high open flow port. The system was designed to use a ball drop to isolate the bottom intervals while fracturing upper intervals. After fracture stimulation, the fracture seat/ball needed to be milled. The production sleeve were designed to be shifted to the open position and the fracturing sleeve to the closed position through mechanical shifting tool to put the well on production. The fracturing sleeve and the production sleeve were located close to each other and a successful shifting operation needed an appropriate shifting tool, with a real-time downhole telemetry system that met the temperature limitations while providing accurate depth control, differential pressure readings, and axial force (tension and compression) measurements. Hydraulic-pressure-activated shifting tools were used to manipulate the sleeves. A coiled tubing (CT) rugged downhole tool with real-time telemetry was used to run the shifting tools. Yard tests were conducted to identify the optimum rates and pressures to actuate the hydraulically activated shifting tools and study their behavior. The expansion of the fracturing sleeve shifting tool keys initiated at 1.6 bbl/min (400 psi) and the keys were fully expanded at 1.8 bbl/min (600 psi), whereas the expansion of production sleeve shifting tool keys initiated at 0.3 bbl/min (700 psi), and the keys were fully expanded at 0.4 bbl/min (900 psi). During the design and planning of the shifting operation, simulations were conducted, and surface and downhole tools were selected carefully to ensure the CT could provide enough downhole upward force (5,000 to 6,000 lbf) to close the fracture ports and 2,000 to 4,000 lbf to open production sleeves. Following the fracturing operation, the first CT run aimed to mill fracture seats/balls to clear the path for the subsequent shifting operation. In the second CT run, all the fracturing sleeves were shifted to the closed position while production sleeves were shifted to the open position. The CT rugged downhole tool proved critical for depth correlation and accurate placement of the shifting tools. The real-time downhole acquisition of differential pressure across the toolstring also allowed operating the shifting tools under optimum conditions, while downhole force readings of tension and compression confirmed the shifting of completion accessories. Two fracturing sleeves were shifted to the closed position at 2.4 bbl/min and 700-psi downhole differential pressure, with the downhole weights of 700 lb and 1,000 lbf. Three production sleeves were shifted to open position at 0.6 bbl/min and 1,200-psi downhole differential pressure, and the maximum surface and downhole weights recorded were 73,000 lb and 19,
{"title":"Successful Intervention of Coiled Tubing Rugged Tool with Real-Time Telemetry System in Saudi Arabia First Multistage Fracturing Completion with Sand Control System","authors":"Ahmed. N. Alduaij, Z. Al-Bensaad, D. Ahmed, M. Noor, Nabil Batita, AbdulMuqtadir Khan","doi":"10.2118/205943-ms","DOIUrl":"https://doi.org/10.2118/205943-ms","url":null,"abstract":"\u0000 An openhole multistage completion required selective fracture stimulation, flow control, and sand control in each zone. An openhole multistage completion was designed by combining a production sleeve integrated with sand screens and inflow control devices and a fracture sleeve with high open flow port. The system was designed to use a ball drop to isolate the bottom intervals while fracturing upper intervals. After fracture stimulation, the fracture seat/ball needed to be milled. The production sleeve were designed to be shifted to the open position and the fracturing sleeve to the closed position through mechanical shifting tool to put the well on production. The fracturing sleeve and the production sleeve were located close to each other and a successful shifting operation needed an appropriate shifting tool, with a real-time downhole telemetry system that met the temperature limitations while providing accurate depth control, differential pressure readings, and axial force (tension and compression) measurements.\u0000 Hydraulic-pressure-activated shifting tools were used to manipulate the sleeves. A coiled tubing (CT) rugged downhole tool with real-time telemetry was used to run the shifting tools. Yard tests were conducted to identify the optimum rates and pressures to actuate the hydraulically activated shifting tools and study their behavior. The expansion of the fracturing sleeve shifting tool keys initiated at 1.6 bbl/min (400 psi) and the keys were fully expanded at 1.8 bbl/min (600 psi), whereas the expansion of production sleeve shifting tool keys initiated at 0.3 bbl/min (700 psi), and the keys were fully expanded at 0.4 bbl/min (900 psi). During the design and planning of the shifting operation, simulations were conducted, and surface and downhole tools were selected carefully to ensure the CT could provide enough downhole upward force (5,000 to 6,000 lbf) to close the fracture ports and 2,000 to 4,000 lbf to open production sleeves.\u0000 Following the fracturing operation, the first CT run aimed to mill fracture seats/balls to clear the path for the subsequent shifting operation. In the second CT run, all the fracturing sleeves were shifted to the closed position while production sleeves were shifted to the open position. The CT rugged downhole tool proved critical for depth correlation and accurate placement of the shifting tools. The real-time downhole acquisition of differential pressure across the toolstring also allowed operating the shifting tools under optimum conditions, while downhole force readings of tension and compression confirmed the shifting of completion accessories.\u0000 Two fracturing sleeves were shifted to the closed position at 2.4 bbl/min and 700-psi downhole differential pressure, with the downhole weights of 700 lb and 1,000 lbf. Three production sleeves were shifted to open position at 0.6 bbl/min and 1,200-psi downhole differential pressure, and the maximum surface and downhole weights recorded were 73,000 lb and 19,","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80717323","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}
There are several reasons for obtaining gyroscopic surveys in directional wells. A gyro measurement provides reliable data when magnetic measurements are affected by interference from nearby wells; it can significantly reduce the positional uncertainty and provides redundancy data and gross error checks on MWD surveys. However, the complexity and extent of the necessary testing and handling of the tools have prevented widespread adoption, and gyro services have remained limited to "must-have" scenarios. The benefits of solid-state technology and new developments in communication capabilities are gradually changing the way of thinking related to wellbore positioning. The first gyro while drilling tools were introduced in the early 2000s and were based on spinning mass gyro technology. These gyros can be very accurate with low noise levels and drift; however, they are fragile, built with moving parts, and susceptible to calibration shifts. Extensive pre-job testing, validation during job execution and post-job analysis are required to obtain reliable directional survey data. Solid-state gyros have reached the same, or even better, levels of noise and drift without the fragility of their spinning mass counterpart. With different degrees of complexity and coverage, remote operations have been used for many years in the oilfield. Still, the adoption of monitoring gyro services with no personnel at the rig-site has been minimal due to the described complexity of the system and the small volume of jobs that prevented investment and the development of the necessary processes. Solid-state gyro technology addresses these challenges More than 30 gyro-while-drilling jobs have successfully run remotely. The changes in operational procedures forced by the Covid-19 pandemic accelerated the demand for uncrewed operations, and solid-state gyro technology has shown high reliability with zero non-productive time due to tool failures or shifts in the calibration. This new way of working also results in a significant reduction in the environmental impact of the operations as all travel related to personnel and equipment has been reduced and battery life extended by up to 10. Several scenarios related to wellbore positioning and directional drilling greatly benefit by having a gyro in the BHA. The gyro technology and the workflow described in this paper show how this can be done reliably, maintaining the quality of the survey data and reducing the environmental impact.
{"title":"Solid-State Gyro Technology Allows Safe And Reliable Real-Time Remote Operations","authors":"Adrian G. Ledroz, Barry Smart, Navin. Maharaj","doi":"10.2118/205870-ms","DOIUrl":"https://doi.org/10.2118/205870-ms","url":null,"abstract":"\u0000 There are several reasons for obtaining gyroscopic surveys in directional wells. A gyro measurement provides reliable data when magnetic measurements are affected by interference from nearby wells; it can significantly reduce the positional uncertainty and provides redundancy data and gross error checks on MWD surveys. However, the complexity and extent of the necessary testing and handling of the tools have prevented widespread adoption, and gyro services have remained limited to \"must-have\" scenarios. The benefits of solid-state technology and new developments in communication capabilities are gradually changing the way of thinking related to wellbore positioning.\u0000 The first gyro while drilling tools were introduced in the early 2000s and were based on spinning mass gyro technology. These gyros can be very accurate with low noise levels and drift; however, they are fragile, built with moving parts, and susceptible to calibration shifts. Extensive pre-job testing, validation during job execution and post-job analysis are required to obtain reliable directional survey data. Solid-state gyros have reached the same, or even better, levels of noise and drift without the fragility of their spinning mass counterpart.\u0000 With different degrees of complexity and coverage, remote operations have been used for many years in the oilfield. Still, the adoption of monitoring gyro services with no personnel at the rig-site has been minimal due to the described complexity of the system and the small volume of jobs that prevented investment and the development of the necessary processes. Solid-state gyro technology addresses these challenges\u0000 More than 30 gyro-while-drilling jobs have successfully run remotely. The changes in operational procedures forced by the Covid-19 pandemic accelerated the demand for uncrewed operations, and solid-state gyro technology has shown high reliability with zero non-productive time due to tool failures or shifts in the calibration. This new way of working also results in a significant reduction in the environmental impact of the operations as all travel related to personnel and equipment has been reduced and battery life extended by up to 10.\u0000 Several scenarios related to wellbore positioning and directional drilling greatly benefit by having a gyro in the BHA. The gyro technology and the workflow described in this paper show how this can be done reliably, maintaining the quality of the survey data and reducing the environmental impact.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89605479","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}
Brendan Smith, Stuart Buckingham, Daniel F. Touzel, A. Corbett, Charles Tavner
With atmospheric methane concentrations rising, spurring increased social concern, there is a renewed focus in the oil and gas industry on methane emission monitoring and control. In 2019, a methane emission survey at a bp asset west of Shetland was conducted using a closed-cavity methane spectrometer mounted onboard a long-endurance fixed-wing unmanned aerial vehicle (UAV). This flight represents the first methane emissions survey of an offshore facility with a miniature methane spectrometer onboard a UAV with subsequent flights performed. The campaign entailed gathering high-density methane concentration data in a cylindrical flight pattern that circumnavigated the facility in close proximity. A small laser spectrometer was modified from an open-cavity system to a closed-cavity onboard the aircraft and yielded in-flight detection limits (3s) of 1065ppb methane above background for the 2019/2020 sensor version and 150ppb for the 2021 sensor versions. Through simulation, the sensors minimum detection limits in mass flow rate were determined to be 50 kg/h for the 2019/2020 campaign and 2.5kg/h for the 2021 campaigns; translating to an obtainable measurement for 23% and 82% of assets reporting higher than 1 kg/h according to the 2019 EEMS dataset, respectively. To operationalize the approach, a simulation tool for flight planning was developed utilizing a gaussian plume model and a scaled coefficient of variation to invoke expected methane concentration fluctuations at short time intervals. The simulation is additionally used for creation of synthetic datasets to test and validate algorithm development. Two methods were developed to calculate offshore facility level emission rates from the geolocated methane concentration data acquired during the emission surveys. Furthermore, a gaussian plume simulator was developed to predict plume behavior and aid in error analysis. These methods are under evaluation, but all allow for the rapid processing (<24h) of results upon landing the aircraft. Additional flights were conducted in 2020 and 2021 with bp and several UK North Sea Operators through Net Zero Technology Centre (NZTC) funded project, resulting in a total of 18 methane emission survey flights to 11 offshore assets between 2019 and 2021. The 2019 flight, and subsequent 2020/21 flights, demonstrated the potential of the technology to derive facility level emission rates to verify industry emission performance and data.
{"title":"Development of Methods for Top-Down Methane Emission Measurements of Oil and Gas Facilities in an Offshore Environment Using a Miniature Methane Spectrometer and Long-Endurance UAS","authors":"Brendan Smith, Stuart Buckingham, Daniel F. Touzel, A. Corbett, Charles Tavner","doi":"10.2118/206181-ms","DOIUrl":"https://doi.org/10.2118/206181-ms","url":null,"abstract":"\u0000 With atmospheric methane concentrations rising, spurring increased social concern, there is a renewed focus in the oil and gas industry on methane emission monitoring and control. In 2019, a methane emission survey at a bp asset west of Shetland was conducted using a closed-cavity methane spectrometer mounted onboard a long-endurance fixed-wing unmanned aerial vehicle (UAV). This flight represents the first methane emissions survey of an offshore facility with a miniature methane spectrometer onboard a UAV with subsequent flights performed. The campaign entailed gathering high-density methane concentration data in a cylindrical flight pattern that circumnavigated the facility in close proximity. A small laser spectrometer was modified from an open-cavity system to a closed-cavity onboard the aircraft and yielded in-flight detection limits (3s) of 1065ppb methane above background for the 2019/2020 sensor version and 150ppb for the 2021 sensor versions. Through simulation, the sensors minimum detection limits in mass flow rate were determined to be 50 kg/h for the 2019/2020 campaign and 2.5kg/h for the 2021 campaigns; translating to an obtainable measurement for 23% and 82% of assets reporting higher than 1 kg/h according to the 2019 EEMS dataset, respectively. To operationalize the approach, a simulation tool for flight planning was developed utilizing a gaussian plume model and a scaled coefficient of variation to invoke expected methane concentration fluctuations at short time intervals. The simulation is additionally used for creation of synthetic datasets to test and validate algorithm development. Two methods were developed to calculate offshore facility level emission rates from the geolocated methane concentration data acquired during the emission surveys. Furthermore, a gaussian plume simulator was developed to predict plume behavior and aid in error analysis. These methods are under evaluation, but all allow for the rapid processing (<24h) of results upon landing the aircraft. Additional flights were conducted in 2020 and 2021 with bp and several UK North Sea Operators through Net Zero Technology Centre (NZTC) funded project, resulting in a total of 18 methane emission survey flights to 11 offshore assets between 2019 and 2021. The 2019 flight, and subsequent 2020/21 flights, demonstrated the potential of the technology to derive facility level emission rates to verify industry emission performance and data.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89671921","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}
D. C. Braga, M. Kamyab, D. Joshi, Brian Harclerode, C. Cheatham
One of the responsibilities of a directional driller (DD) is the computation of the current bit position given the last survey station measurement, and with that information calculate the path back to plan if directional correction is needed. Having only a few minutes during a drilling connection to perform these calculations, the DD is limited to compute only a handful of possible paths that will be presented to the Drilling Engineer/Company Man. With this information, the Company Man will decide which path to follow. The present work aims to develop a computer algorithm that replicates the field knowledge of DDs but can compute hundreds of paths in less than one minute. In addition, since the objective of the trajectory correction may differ, the algorithm also can optimize for one of three goals: maximum rate of penetration (ROP), minimum tortuosity in the path, or maximum footage in the drilling target window. The paper presents examples of four different path recommendations in the lateral portion of a horizontal well. The results show the optimum recommended paths for the same position for a specific optimization goal. Finally, a comparison between the running time and number of paths computed is presented. All results were obtained during the validation tests of the algorithm.
{"title":"Using Particle Swarm Optimization to Compute Hundreds of Possible Directional Paths to Get Back/Stay in the Drilling Window","authors":"D. C. Braga, M. Kamyab, D. Joshi, Brian Harclerode, C. Cheatham","doi":"10.2118/206170-ms","DOIUrl":"https://doi.org/10.2118/206170-ms","url":null,"abstract":"\u0000 One of the responsibilities of a directional driller (DD) is the computation of the current bit position given the last survey station measurement, and with that information calculate the path back to plan if directional correction is needed. Having only a few minutes during a drilling connection to perform these calculations, the DD is limited to compute only a handful of possible paths that will be presented to the Drilling Engineer/Company Man. With this information, the Company Man will decide which path to follow. The present work aims to develop a computer algorithm that replicates the field knowledge of DDs but can compute hundreds of paths in less than one minute. In addition, since the objective of the trajectory correction may differ, the algorithm also can optimize for one of three goals: maximum rate of penetration (ROP), minimum tortuosity in the path, or maximum footage in the drilling target window. The paper presents examples of four different path recommendations in the lateral portion of a horizontal well. The results show the optimum recommended paths for the same position for a specific optimization goal. Finally, a comparison between the running time and number of paths computed is presented. All results were obtained during the validation tests of the algorithm.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79563159","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 post COVID-19 era will undoubtedly present paradigm shifts in operational planning and execution and advanced automation will become an important factor. However, drilling automation without directional drilling (Cayeux 2020) capability will exclude the use of automation in a vast number of fields where precise placement of the wellbore has shifted from a luxury to a necessity. This is important in unconventional plays where automation can make a step change in operational outcomes (Chmela 2020). However, most efforts in automating directional drilling are using bespoke rigs (Slagmulder 2016) and bespoke bottom hole assembly (BHA) that limit operational options. The goal is in designing systems that enable directional drilling automation (Chatar 2018) with existing BHAs. This paper will look at three challenges that were identified and overcome to deploy a vendor agnostic system for automating the directional drilling (DD) process. The three challenges identified here are as follows:Using any mud motor including low-cost motors in a closed loopIntegration with an existing measurement and logging while drilling (MLWD) systemAbility to roll out automation systems on any operations with existing rigs The system is a modification of an operator’s autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs and have minimum footprint on the rigs for operational use. The system will have a dedicated connection to the rig’s programmable logic controller (PLC) via common industrial protocols including Modbus, EthernetIP or Profinet, a physical connection the MLWD receiver and a brain box with a cloud connection to aggregate, process data and send commands to the rig PLC to execute directional commands. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance.
{"title":"Learnings from Building a Vendor Agnostic Automated Directional Drilling System","authors":"Titto Thomas Philip, S. Ziatdinov","doi":"10.2118/205864-ms","DOIUrl":"https://doi.org/10.2118/205864-ms","url":null,"abstract":"\u0000 The post COVID-19 era will undoubtedly present paradigm shifts in operational planning and execution and advanced automation will become an important factor. However, drilling automation without directional drilling (Cayeux 2020) capability will exclude the use of automation in a vast number of fields where precise placement of the wellbore has shifted from a luxury to a necessity. This is important in unconventional plays where automation can make a step change in operational outcomes (Chmela 2020). However, most efforts in automating directional drilling are using bespoke rigs (Slagmulder 2016) and bespoke bottom hole assembly (BHA) that limit operational options. The goal is in designing systems that enable directional drilling automation (Chatar 2018) with existing BHAs.\u0000 This paper will look at three challenges that were identified and overcome to deploy a vendor agnostic system for automating the directional drilling (DD) process. The three challenges identified here are as follows:Using any mud motor including low-cost motors in a closed loopIntegration with an existing measurement and logging while drilling (MLWD) systemAbility to roll out automation systems on any operations with existing rigs\u0000 The system is a modification of an operator’s autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs and have minimum footprint on the rigs for operational use. The system will have a dedicated connection to the rig’s programmable logic controller (PLC) via common industrial protocols including Modbus, EthernetIP or Profinet, a physical connection the MLWD receiver and a brain box with a cloud connection to aggregate, process data and send commands to the rig PLC to execute directional commands.\u0000 A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77463790","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 syllabus getting outdated, classroom attendance getting less importance, fast advancements of technology and changing workforce, and demography require us to rethink and re-examine the core curricula being taught at petroleum schools. The changing landscape like clean energy and carbon neutral delivery are adding pressure to re-examine the subjects taught in the classroom so that the long-term sustainability is established. So, acquiring interdisciplinary skills is crucial with the reformed curricula. The questions to be addressed include: "What is the fundamental problem in the present petroleum education?," "Is there any problem with the present theoretical framework?," "Is the petroleum education aligned with the latest developments such as edge devices, sensors, machine learning and artificial intelligence?," "Is there an academia-industry-regulatory agencies tighter participation?," and "What are the structural changes needed like rebranding as energy engineering?." The paper addresses these questions by proposing a new approach to petroleum engineering education by way of a changed energy engineering program, which involves fundamentals of engineering, sciences, and technologies that culminates in the development of experiential learning on cyber-physical systems.
{"title":"Petroleum Energy Engineering Education Reform: Flipping the Curriculum","authors":"Robello Samuel","doi":"10.2118/206305-ms","DOIUrl":"https://doi.org/10.2118/206305-ms","url":null,"abstract":"\u0000 The syllabus getting outdated, classroom attendance getting less importance, fast advancements of technology and changing workforce, and demography require us to rethink and re-examine the core curricula being taught at petroleum schools. The changing landscape like clean energy and carbon neutral delivery are adding pressure to re-examine the subjects taught in the classroom so that the long-term sustainability is established. So, acquiring interdisciplinary skills is crucial with the reformed curricula.\u0000 The questions to be addressed include: \"What is the fundamental problem in the present petroleum education?,\" \"Is there any problem with the present theoretical framework?,\" \"Is the petroleum education aligned with the latest developments such as edge devices, sensors, machine learning and artificial intelligence?,\" \"Is there an academia-industry-regulatory agencies tighter participation?,\" and \"What are the structural changes needed like rebranding as energy engineering?.\" The paper addresses these questions by proposing a new approach to petroleum engineering education by way of a changed energy engineering program, which involves fundamentals of engineering, sciences, and technologies that culminates in the development of experiential learning on cyber-physical systems.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85731553","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 this study, Layer-by-Layer (LbL) assembled polyelectrolyte multilayered nanoparticles were developed as a technique for targeted and controlled release of enzyme breakers. Polyelectrolyte multilayers (PEMs) were assembled by means of alternate electrostatic adsorption of polyanions and polycations using colloidal structure of polyelectrolyte complexes (PECs) as LbL building blocks. High enzyme concentrations were introduced into polyethyleneimine (PEI), a positively charged polyelectrolyte solution, to form an electrostatic PECs with dextran sulfate (DS), a negatively charged polyelectrolyte solution. Under the right concentrations and pH conditions, PEMs were assembled by alternating deposition of PEI with DS solutions at the colloidal structure of PEI-DS complexes. Stability and reproducibility of PEMs were tested over time. This work demonstrates the significance of PEMs as a technique for the targeted and controlled release of enzymes based on their high loading capacity, high capsulation efficiency, and extreme control over enzyme concentration. Entrapment efficiency (EE%) of polyelectrolyte multilayered nanoparticles were evaluated using concentration measurement methods as enzyme viscometric assays. Controlled release of enzyme entrapped within PEMs was sustained over longer time periods (> 18 hours) through reduction in viscosity, and elastic modulus of borate-crosslinked hydroxypropyl guar (HPG). Long-term fracture conductivity tests at 40℃ under closure stresses of 1,000, 2,000, and 4,000 psi revealed high fracture clean-up efficiency for fracturing fluid mixed with enzyme-loaded PEMs nanoparticles. The retained fracture conductivity improvement from 25% to 60% indicates the impact of controlled distribution of nanoparticles in the filter cake and along the entire fracture face as opposed to the randomly dispersed unentrapped enzyme. Retained fracture conductivity was found to be 34% for fluid systems containing conventional enzyme-loaded PECs. Additionally, enzyme-loaded PEMs demonstrated enhanced nanoparticle distribution, high loading and entrapment efficiency, and sustained release of the enzyme. This allows for the addition of higher enzyme concentrations without compromising the fluid properties during a treatment, thereby effectively degrading the concentrated residual gel to a greater extent. Fluid loss properties of polyelectrolyte multilayered nanoparticles were also studied under static conditions using a high-pressure fluid loss cell. A borate-crosslinked HPG mixed with nanoparticles was filtered against core plugs with similar permeabilities. The addition of multilayered nanoparticles into the fracturing fluid was observed to significantly improve the fluid- loss prevention effect. The spurt-loss coefficient values were also determined to cause lower filtrate volume than those with crosslinked base solutions. The PEI-DS complex bridging effects revealed a denser, colored filter cake indicating a relatively homogenous d
{"title":"Polyelectrolyte Multilayered Nanoparticles as Nanocontainers for Enzyme Breakers During Hydraulic Fracturing Process","authors":"M. Alhajeri, Jenn-Tai Liang, R. B. Ghahfarokhi","doi":"10.2118/205981-ms","DOIUrl":"https://doi.org/10.2118/205981-ms","url":null,"abstract":"\u0000 In this study, Layer-by-Layer (LbL) assembled polyelectrolyte multilayered nanoparticles were developed as a technique for targeted and controlled release of enzyme breakers. Polyelectrolyte multilayers (PEMs) were assembled by means of alternate electrostatic adsorption of polyanions and polycations using colloidal structure of polyelectrolyte complexes (PECs) as LbL building blocks. High enzyme concentrations were introduced into polyethyleneimine (PEI), a positively charged polyelectrolyte solution, to form an electrostatic PECs with dextran sulfate (DS), a negatively charged polyelectrolyte solution. Under the right concentrations and pH conditions, PEMs were assembled by alternating deposition of PEI with DS solutions at the colloidal structure of PEI-DS complexes. Stability and reproducibility of PEMs were tested over time. This work demonstrates the significance of PEMs as a technique for the targeted and controlled release of enzymes based on their high loading capacity, high capsulation efficiency, and extreme control over enzyme concentration. Entrapment efficiency (EE%) of polyelectrolyte multilayered nanoparticles were evaluated using concentration measurement methods as enzyme viscometric assays. Controlled release of enzyme entrapped within PEMs was sustained over longer time periods (> 18 hours) through reduction in viscosity, and elastic modulus of borate-crosslinked hydroxypropyl guar (HPG). Long-term fracture conductivity tests at 40℃ under closure stresses of 1,000, 2,000, and 4,000 psi revealed high fracture clean-up efficiency for fracturing fluid mixed with enzyme-loaded PEMs nanoparticles. The retained fracture conductivity improvement from 25% to 60% indicates the impact of controlled distribution of nanoparticles in the filter cake and along the entire fracture face as opposed to the randomly dispersed unentrapped enzyme. Retained fracture conductivity was found to be 34% for fluid systems containing conventional enzyme-loaded PECs. Additionally, enzyme-loaded PEMs demonstrated enhanced nanoparticle distribution, high loading and entrapment efficiency, and sustained release of the enzyme. This allows for the addition of higher enzyme concentrations without compromising the fluid properties during a treatment, thereby effectively degrading the concentrated residual gel to a greater extent. Fluid loss properties of polyelectrolyte multilayered nanoparticles were also studied under static conditions using a high-pressure fluid loss cell. A borate-crosslinked HPG mixed with nanoparticles was filtered against core plugs with similar permeabilities. The addition of multilayered nanoparticles into the fracturing fluid was observed to significantly improve the fluid- loss prevention effect. The spurt-loss coefficient values were also determined to cause lower filtrate volume than those with crosslinked base solutions. The PEI-DS complex bridging effects revealed a denser, colored filter cake indicating a relatively homogenous d","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87224881","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Elwan, M. Surendra, S. Ghedan, Rami Kansao, Mahmoud Koresh, Hesham Mousa, Agustin Maqui, E. Shahin, M. Valle, I. Arslan, M. Ibrahim, Lamia Rouis, T. Eid
The QQ Field in the Gulf of Suez is a mature, geologically complex with multiple stacked, faulted reservoirs, with commingled production between different reservoirs. This paper illustrates the power of an automated tool to perform systematic, rapid, and detailed assessment of the reservoir performance, identify the key recovery obstacles and prepare remedial plans to enable the reservoir to produce to its full potential. The well and reservoir data were processed to compute a series of metrics and key performance indicators at various levels (well, layer, reservoir, well groups, etc.). The tool has several automated modules to facilitate rapid, metric-driven reservoir assurance and management. These modules include: (i) well production/injection allocation, (ii) wells decline curve analysis including event-detection, (iii) pressure and voidage analysis, and (iv) Contact analysis. Using performance analytics, the study quickly identified ways to improve the health of the reservoir and maximize its value. The QQ Field predominantly produces from two formations: Nubia and Nezzazat. Furthermore, there are multiple sub-layers in each formation. Reliable flow unit allocation is critical to gauge contribution of each layer, identify the undrained areas of the reservoir, and locate future development opportunities. The flow unit allocation module incorporates all available data such as PLT/ILT data, completion history, permeability of each flow unit at well level, relative pressures, and water influx model. Based on the allocated production, the current recovery factors in Nubia and Nezzazat are approximately 60% and 20% respectively. Analysis of RFT data reveals good vertical communication across Nubia. However, in some areas there is clear pressure discontinuity across layers. The reservoir pressure has dropped below the bubble point in both formations. As a result, water injection was initiated. The pressure in all parts of Nubia was restored above bubble point. Aquifer influx is sufficient to support the current withdrawal rates and further water injection is unnecessary. However, Nezzazat has a significantly higher reservoir complexity and therefore, shows a large variation in pressure behavior. It needs water injection to maintain the reservoir pressure above the bubble point in all parts of the reservoir. Based on the flow-unit allocation, the voidage replacement ratio (VRR) was calculated for each area and each layer. Even though the overall VRR in the waterflooded areas is above one, the distribution of the injected water is uneven. Redistributing injected water and ensuring that all the areas and all the layers are adequately supported will help to maximize recovery. The prolonged dip in oil price demands extreme efficiency. Sound reservoir management must not require unreasonable time or manpower. The rapid, automated analysis enables quick identification of the key areas for improvement in reservoir management practices and maximize the v
{"title":"Artificial Intelligence-Based, Automated Rapid Reservoir Assurance and Reservoir Health Diagnostics in a Complex Offshore Mature Field","authors":"M. Elwan, M. Surendra, S. Ghedan, Rami Kansao, Mahmoud Koresh, Hesham Mousa, Agustin Maqui, E. Shahin, M. Valle, I. Arslan, M. Ibrahim, Lamia Rouis, T. Eid","doi":"10.2118/206077-ms","DOIUrl":"https://doi.org/10.2118/206077-ms","url":null,"abstract":"\u0000 The QQ Field in the Gulf of Suez is a mature, geologically complex with multiple stacked, faulted reservoirs, with commingled production between different reservoirs. This paper illustrates the power of an automated tool to perform systematic, rapid, and detailed assessment of the reservoir performance, identify the key recovery obstacles and prepare remedial plans to enable the reservoir to produce to its full potential. The well and reservoir data were processed to compute a series of metrics and key performance indicators at various levels (well, layer, reservoir, well groups, etc.). The tool has several automated modules to facilitate rapid, metric-driven reservoir assurance and management. These modules include: (i) well production/injection allocation, (ii) wells decline curve analysis including event-detection, (iii) pressure and voidage analysis, and (iv) Contact analysis. Using performance analytics, the study quickly identified ways to improve the health of the reservoir and maximize its value.\u0000 The QQ Field predominantly produces from two formations: Nubia and Nezzazat. Furthermore, there are multiple sub-layers in each formation. Reliable flow unit allocation is critical to gauge contribution of each layer, identify the undrained areas of the reservoir, and locate future development opportunities. The flow unit allocation module incorporates all available data such as PLT/ILT data, completion history, permeability of each flow unit at well level, relative pressures, and water influx model. Based on the allocated production, the current recovery factors in Nubia and Nezzazat are approximately 60% and 20% respectively. Analysis of RFT data reveals good vertical communication across Nubia. However, in some areas there is clear pressure discontinuity across layers. The reservoir pressure has dropped below the bubble point in both formations. As a result, water injection was initiated. The pressure in all parts of Nubia was restored above bubble point. Aquifer influx is sufficient to support the current withdrawal rates and further water injection is unnecessary. However, Nezzazat has a significantly higher reservoir complexity and therefore, shows a large variation in pressure behavior. It needs water injection to maintain the reservoir pressure above the bubble point in all parts of the reservoir. Based on the flow-unit allocation, the voidage replacement ratio (VRR) was calculated for each area and each layer. Even though the overall VRR in the waterflooded areas is above one, the distribution of the injected water is uneven. Redistributing injected water and ensuring that all the areas and all the layers are adequately supported will help to maximize recovery. The prolonged dip in oil price demands extreme efficiency. Sound reservoir management must not require unreasonable time or manpower. The rapid, automated analysis enables quick identification of the key areas for improvement in reservoir management practices and maximize the v","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88259549","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}
Elijah Kiplimo, D. Oyoo, Antonio Tapia, Marseline Jepng’etich
Wellheads have a major role in ensuring well integrity, providing access to the wellbore and flow control. It is vital to constantly monitor the wellhead fluid pressure and temperature effectively in order to maintain the full control of wellbore fluids. Over the years, wellheads have remained purely mechanical and have heavily relied on physical on-site monitoring. There is need to develop a reliable and accessible monitoring solutions for the wellheads in order to increase the effectiveness of the well integrity management systems and to get the full benefits of the wellhead data by incorporating the emerging data analytics technologies. This project details the development of a system that gathers wellhead temperature, pressure and the accurate valve position at any given time. The data gathering systems used in this project entail smart sensor technology capable of withstanding the wellbore pressures and temperatures. The system transmits the data securely, using blockchain, to an online platform where advanced data analytics using MATLAB and machine learning algorithms are used for visual data representation. The online platform additionally provides a means of real-time valve position control and takes into account the exact revolutions required for the opening and closure of the valve hence keeping a record for maintenance purposes. The innovative use and analysis of the data gathered form the wellhead provides insights for the operators and service companies and gives a way for setting ang thresholds in order to get alerts based in their custom specifications. This paper documents the development of a system that gathers wellhead data and provides a means of remote control of the wellhead valves. It covers the design phase, selection of appropriate sensor placement locations on the wellhead, the design of valve actuators, offline data gathering systems and the online data analysis and valve control platform. The project also pays a key attention towards the secure data transmission techniques and highlights the benefits of incorporating such a system in the oil and gas upstream sector.
{"title":"Development of a System for Remote Control and Monitoring of Wellheads","authors":"Elijah Kiplimo, D. Oyoo, Antonio Tapia, Marseline Jepng’etich","doi":"10.2118/206060-ms","DOIUrl":"https://doi.org/10.2118/206060-ms","url":null,"abstract":"\u0000 Wellheads have a major role in ensuring well integrity, providing access to the wellbore and flow control. It is vital to constantly monitor the wellhead fluid pressure and temperature effectively in order to maintain the full control of wellbore fluids. Over the years, wellheads have remained purely mechanical and have heavily relied on physical on-site monitoring. There is need to develop a reliable and accessible monitoring solutions for the wellheads in order to increase the effectiveness of the well integrity management systems and to get the full benefits of the wellhead data by incorporating the emerging data analytics technologies.\u0000 This project details the development of a system that gathers wellhead temperature, pressure and the accurate valve position at any given time. The data gathering systems used in this project entail smart sensor technology capable of withstanding the wellbore pressures and temperatures. The system transmits the data securely, using blockchain, to an online platform where advanced data analytics using MATLAB and machine learning algorithms are used for visual data representation. The online platform additionally provides a means of real-time valve position control and takes into account the exact revolutions required for the opening and closure of the valve hence keeping a record for maintenance purposes. The innovative use and analysis of the data gathered form the wellhead provides insights for the operators and service companies and gives a way for setting ang thresholds in order to get alerts based in their custom specifications. This paper documents the development of a system that gathers wellhead data and provides a means of remote control of the wellhead valves. It covers the design phase, selection of appropriate sensor placement locations on the wellhead, the design of valve actuators, offline data gathering systems and the online data analysis and valve control platform. The project also pays a key attention towards the secure data transmission techniques and highlights the benefits of incorporating such a system in the oil and gas upstream sector.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86603793","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}
Xinlei Shi, Jiansheng Zhang, Yunlong Lu, Zhilei Han, Yifan He
The classification of water flooding severity is crucial for planning reservoir production and improving the recovery ratio. In this paper, we study a siliciclastic heavy oil reservoir in Bohai Bay, with resistivity reading close to, or even lower than the wet zone (3~5Ω.m). In this environment, computing original reservoir Sw using Traditional hydrocarbon saturation equation is challenging. As a result, the displacement efficiency of a water drive cannot be accurately determined. In order to properly evaluate displacement efficiency, we must estimate initial reservoir Sw (Swirr) and the modern day Sw. Sw can typically be estimated from NMR data with a proper T2 time cutoff. However, in heavy oil reservoirs, the relaxation times of oil and capillary bound water overlap, leading to an over-estimation of Sw. We propose to compensate for the heavy oil effect by adjusting the cutoff until NMR Sw matches the Sw from core Mercury Injection for Capillary Pressure (MICP). As oilfield development proceeds, water displaces some oil in the pore space. Since the injected water has higher salinity than reservoir water, formation resistivity (Rw) becomes lower. Based on the material balance theory, the variable multiple water injection material balance equation is established, and the equation set is established by combining the material balance equation with the Simandoux equation and the calculation formula of mixed water resistivity (Rwz). According to the rock electricity experiment under different salinity, the dynamic rock electricity parameters are used in the Simandoux equation, and the mixed water resistivity and modern day Sw after water flooding are solved iteratively under the original SW constraint. The displacement efficiency is calculated as the difference between Sw and modern day Sw. The proposed method was applied to 10 wells and improved the Sw accuracy by 5%-15%. The continuous solution Rw from our method matches Rw measured in the lab. The calculated displacement efficiency is compared with actual production history and the accuracy improved from 68% to 80%.
{"title":"Quantitative Evaluation of Water Flooding in a Low Resistivity Heavy Oil Reservoir with NMR and Conventional Logs","authors":"Xinlei Shi, Jiansheng Zhang, Yunlong Lu, Zhilei Han, Yifan He","doi":"10.2118/205928-ms","DOIUrl":"https://doi.org/10.2118/205928-ms","url":null,"abstract":"\u0000 The classification of water flooding severity is crucial for planning reservoir production and improving the recovery ratio. In this paper, we study a siliciclastic heavy oil reservoir in Bohai Bay, with resistivity reading close to, or even lower than the wet zone (3~5Ω.m). In this environment, computing original reservoir Sw using Traditional hydrocarbon saturation equation is challenging. As a result, the displacement efficiency of a water drive cannot be accurately determined.\u0000 In order to properly evaluate displacement efficiency, we must estimate initial reservoir Sw (Swirr) and the modern day Sw. Sw can typically be estimated from NMR data with a proper T2 time cutoff. However, in heavy oil reservoirs, the relaxation times of oil and capillary bound water overlap, leading to an over-estimation of Sw. We propose to compensate for the heavy oil effect by adjusting the cutoff until NMR Sw matches the Sw from core Mercury Injection for Capillary Pressure (MICP). As oilfield development proceeds, water displaces some oil in the pore space. Since the injected water has higher salinity than reservoir water, formation resistivity (Rw) becomes lower. Based on the material balance theory, the variable multiple water injection material balance equation is established, and the equation set is established by combining the material balance equation with the Simandoux equation and the calculation formula of mixed water resistivity (Rwz). According to the rock electricity experiment under different salinity, the dynamic rock electricity parameters are used in the Simandoux equation, and the mixed water resistivity and modern day Sw after water flooding are solved iteratively under the original SW constraint. The displacement efficiency is calculated as the difference between Sw and modern day Sw.\u0000 The proposed method was applied to 10 wells and improved the Sw accuracy by 5%-15%. The continuous solution Rw from our method matches Rw measured in the lab. The calculated displacement efficiency is compared with actual production history and the accuracy improved from 68% to 80%.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89832770","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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