Ahmed Khalaf, B. Norman, S. Alquwizani, H. Almalki, Meshal Ergesous, Mohammed AlSowaier
Electrical submersible pump (ESP) trips and unplanned shutdowns can be a major operational challenge for many oil fields. In most of these ESP trips, the ESP can be returned back to production after conducting proper troubleshooting at surface and without any downhole intervention. The process of manually restarting tripped ESPs can be a complex and costly operation, especially in an offshore environment. Alternatively, automatic ESP restart can offer great advantages by reducing the ESP downtime. Many of the variable speed drives (VSDs) available in the market offer an auto restart feature that allows the ESP to be restarted automatically without human intervention. This paper presents the concept and the application of this technique. The activation of ESP auto restart requires considerable technical review of the different trip causes and the proper restart methodology for each. Auto restart of each trip type has to be programed differently to prevent possible harm to the ESP. Specific engineering measures and procedures shall be put in place to ensure personnel and equipment safety. In this paper, some statistical tools for ESP trips and restarts are presented to measure the success of auto restart, its effectiveness, and its limitations. The obtained results from the ESP auto-restart technique show it to be both practical and beneficial; it can significantly reduce the time to put the ESP back in operation resulting in production advancement. In addition, continuous data collection and assessment of auto-restart events play an important factor in ensuring that auto-restart settings are properly applied and adjusted for each type of variable speed drive installed in the field. Finally, the paper provides several recommendations with suggested ways to improve the functionality of this feature. The technique introduced in this paper can bring artificially lifted fields closer to an autonomous and intelligent concept of operations. The presented model can serve as a good benchmarking tool for future implementation of artificial lift automation.
{"title":"Moving to an Autonomous Artificial Lift Concept through Automatic ESP Restart","authors":"Ahmed Khalaf, B. Norman, S. Alquwizani, H. Almalki, Meshal Ergesous, Mohammed AlSowaier","doi":"10.2118/197339-ms","DOIUrl":"https://doi.org/10.2118/197339-ms","url":null,"abstract":"\u0000 Electrical submersible pump (ESP) trips and unplanned shutdowns can be a major operational challenge for many oil fields. In most of these ESP trips, the ESP can be returned back to production after conducting proper troubleshooting at surface and without any downhole intervention. The process of manually restarting tripped ESPs can be a complex and costly operation, especially in an offshore environment. Alternatively, automatic ESP restart can offer great advantages by reducing the ESP downtime.\u0000 Many of the variable speed drives (VSDs) available in the market offer an auto restart feature that allows the ESP to be restarted automatically without human intervention. This paper presents the concept and the application of this technique. The activation of ESP auto restart requires considerable technical review of the different trip causes and the proper restart methodology for each. Auto restart of each trip type has to be programed differently to prevent possible harm to the ESP. Specific engineering measures and procedures shall be put in place to ensure personnel and equipment safety.\u0000 In this paper, some statistical tools for ESP trips and restarts are presented to measure the success of auto restart, its effectiveness, and its limitations. The obtained results from the ESP auto-restart technique show it to be both practical and beneficial; it can significantly reduce the time to put the ESP back in operation resulting in production advancement. In addition, continuous data collection and assessment of auto-restart events play an important factor in ensuring that auto-restart settings are properly applied and adjusted for each type of variable speed drive installed in the field. Finally, the paper provides several recommendations with suggested ways to improve the functionality of this feature.\u0000 The technique introduced in this paper can bring artificially lifted fields closer to an autonomous and intelligent concept of operations. The presented model can serve as a good benchmarking tool for future implementation of artificial lift automation.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"203 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74148115","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 main objective of this paper is to present a cost-effective, user-friendly and highly reliable subsea pipeline design automation framework under the cloud-based digital field twin platform Subsea-XD. The FEED and detail design phase of the subsea pipeline is normally quite long and need to run several analyses sequentially to achieve the desired results. In this cloud-based design automation method, a significant number of calculation hours are saved due to systematic and sequential approach with minimum remediation work by reducing human error. In this proposed design automation framework, all the standard pipeline calculations including code checks are performed through a web-based graphical user interface (GUI) designed in cloud-based digital field twin. In the design phase of the subsea pipeline, some more advanced level pipeline finite element analyses are performed for buckling and walking assessment. The design phase of the subsea pipeline consists of different analytical as well as finite element (FE) calculations which are performed systematically and sequentially in cloud-based digital field twin. Various calculations including wall thickness calculation based on API/DNV/ASME code check, on-bottom stability analysis, pipeline span analysis, pipeline end expansion analysis, out of straightness analysis and pipeline buckling analysis are performed sequentially and systematically in the cloud using the metadata information available from the digital field data. All the standard pipeline calculations are developed using Python API and connected to cloud-based digital twin Subsea-XD. For advanced FE analyses for lateral buckling and pipeline walking, the preliminary susceptibilities are assessed through analytical calculations developed through python- based API. For the pipeline FE analysis for lateral buckling and walking assessment, pre-processor and post-processor are developed in python based on various metadata (pipe data, soil, environment) information available in the subsea digital field. The pipeline design calculation outputs are stored in a standardised report format in the cloud platform. The GUI is developed and the whole pipeline design process is automated through the python API. This design automation approach significantly reduces the total project cost. Integrating all the pipeline design calculations and automated report generation in a cloud-based digital field twin is very much beneficial for the early stages where some changes are expected. This pipeline design automation system relates to cloud-based digital field Subsea XD through API so that it is worked as an integrated system giving 3D digital field diagram as well as all pipeline design calculations in one digital platform.
{"title":"Subsea Pipeline Design Automation Using Digital Field Twin","authors":"S. Bhowmik, Gautier Noiray, Harit Naik","doi":"10.2118/197394-ms","DOIUrl":"https://doi.org/10.2118/197394-ms","url":null,"abstract":"\u0000 The main objective of this paper is to present a cost-effective, user-friendly and highly reliable subsea pipeline design automation framework under the cloud-based digital field twin platform Subsea-XD. The FEED and detail design phase of the subsea pipeline is normally quite long and need to run several analyses sequentially to achieve the desired results. In this cloud-based design automation method, a significant number of calculation hours are saved due to systematic and sequential approach with minimum remediation work by reducing human error.\u0000 In this proposed design automation framework, all the standard pipeline calculations including code checks are performed through a web-based graphical user interface (GUI) designed in cloud-based digital field twin. In the design phase of the subsea pipeline, some more advanced level pipeline finite element analyses are performed for buckling and walking assessment. The design phase of the subsea pipeline consists of different analytical as well as finite element (FE) calculations which are performed systematically and sequentially in cloud-based digital field twin. Various calculations including wall thickness calculation based on API/DNV/ASME code check, on-bottom stability analysis, pipeline span analysis, pipeline end expansion analysis, out of straightness analysis and pipeline buckling analysis are performed sequentially and systematically in the cloud using the metadata information available from the digital field data. All the standard pipeline calculations are developed using Python API and connected to cloud-based digital twin Subsea-XD. For advanced FE analyses for lateral buckling and pipeline walking, the preliminary susceptibilities are assessed through analytical calculations developed through python- based API. For the pipeline FE analysis for lateral buckling and walking assessment, pre-processor and post-processor are developed in python based on various metadata (pipe data, soil, environment) information available in the subsea digital field.\u0000 The pipeline design calculation outputs are stored in a standardised report format in the cloud platform. The GUI is developed and the whole pipeline design process is automated through the python API. This design automation approach significantly reduces the total project cost. Integrating all the pipeline design calculations and automated report generation in a cloud-based digital field twin is very much beneficial for the early stages where some changes are expected.\u0000 This pipeline design automation system relates to cloud-based digital field Subsea XD through API so that it is worked as an integrated system giving 3D digital field diagram as well as all pipeline design calculations in one digital platform.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74050411","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}
Abdulaziz Alqasim, S. Kokal, S. Hartvig, O. Huseby
Tracer technology has gained considerable attention recently as an effective tool in the reservoir monitoring and surveillance toolkit, particularly in IOR operations. Gas flow paths within the reservoir can be quite different from liquid (oil and water) flow path. This is primarily due to gravity override, and differences in density and relative permeability between the gas and liquid phases. Inter-well gas tracer test (IWGTT) is a key monitoring and surveillance tool for any IOR projects. IWGTT should be designed and implemented to track the flow behavior of gas phase. The test generally entails injecting a small amount of unique perflouro-hydrocarbon tracers into the gas phase injectant stream. IWGTT have been conducted on a limited number of fields across the globe, and sample results of some will be presented. The sampling frequency of the tracers from the producers should be designed carefully to collect the necessary data that will provide insights about the connectivity between the injectors and producers well pairs, gas breakthrough times ("time of flight"), and possible inter-well fluid saturations. Different fit-for-purpose unique tracers can be deployed in the subject injector(s) stream and their elution can be monitored in the corresponding up-dip producer(s). In addition to reservoir connectivity and break-through times between injector and producer pairs, an IWGTT helps in optimizing WAG operations and production strategies for gas injection projects, improve sweep efficiency and ultimately enhance oil recovery. It can also be used to identify source of inadvertent gas leakage into shallow aquifers or soil gas, and help in the planning and placement of future wells. This paper reviews the workflow and necessary logistics for the successful deployment of an inter-well gas tracer test. It will provide the best practices for designing, sampling, analyzing and interpretation of a gas tracer deployment. The paper also highlights the benefits of gas tracer data and their usefulness in understanding well interconnectivity and dynamic fluid flow in the reservoir. The results can be used to refine the reservoir simulation model and fine tune its parameters. This effort should lead to better reservoir description and an improved dynamic simulation model. The challenges associated with IWGTT will also be shared.
{"title":"Reservoir Description Insights from Inter-well Gas Tracer Test","authors":"Abdulaziz Alqasim, S. Kokal, S. Hartvig, O. Huseby","doi":"10.2118/197967-ms","DOIUrl":"https://doi.org/10.2118/197967-ms","url":null,"abstract":"\u0000 Tracer technology has gained considerable attention recently as an effective tool in the reservoir monitoring and surveillance toolkit, particularly in IOR operations. Gas flow paths within the reservoir can be quite different from liquid (oil and water) flow path. This is primarily due to gravity override, and differences in density and relative permeability between the gas and liquid phases.\u0000 Inter-well gas tracer test (IWGTT) is a key monitoring and surveillance tool for any IOR projects. IWGTT should be designed and implemented to track the flow behavior of gas phase. The test generally entails injecting a small amount of unique perflouro-hydrocarbon tracers into the gas phase injectant stream. IWGTT have been conducted on a limited number of fields across the globe, and sample results of some will be presented.\u0000 The sampling frequency of the tracers from the producers should be designed carefully to collect the necessary data that will provide insights about the connectivity between the injectors and producers well pairs, gas breakthrough times (\"time of flight\"), and possible inter-well fluid saturations. Different fit-for-purpose unique tracers can be deployed in the subject injector(s) stream and their elution can be monitored in the corresponding up-dip producer(s).\u0000 In addition to reservoir connectivity and break-through times between injector and producer pairs, an IWGTT helps in optimizing WAG operations and production strategies for gas injection projects, improve sweep efficiency and ultimately enhance oil recovery. It can also be used to identify source of inadvertent gas leakage into shallow aquifers or soil gas, and help in the planning and placement of future wells.\u0000 This paper reviews the workflow and necessary logistics for the successful deployment of an inter-well gas tracer test. It will provide the best practices for designing, sampling, analyzing and interpretation of a gas tracer deployment. The paper also highlights the benefits of gas tracer data and their usefulness in understanding well interconnectivity and dynamic fluid flow in the reservoir. The results can be used to refine the reservoir simulation model and fine tune its parameters. This effort should lead to better reservoir description and an improved dynamic simulation model. The challenges associated with IWGTT will also be shared.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"115 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74509499","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}
Vidya Sudevan, Amit Shukla, Arjun Sharma, V. Bhadran, H. Karki
Middle Eastern countries have the most complex and extensive oil and gas pipeline network in the world and are expected to have a total length of 24066.9km of pipelines by 2022. Routine inspection and active maintenance of these structures thus have high priority in the oil and gas operations. Pigging, the commonly used internal inspection method is expensive and the need for pre-installation procedures for flawless pig operations makes it time-consuming. The external inspection is currently done manually by a group of operators who either drives or walks over the buried pipeline structures. The visual/sensor data collected using various handheld devices are then analyzed manually to identify/locate the possible anomalies. The accuracy of data collected and their analysis highly depends upon the experience of the operators. Also, the extreme environmental conditions like high temperature and uneven terrain make the manual inspection a tedious task. The challenges in the current manual inspection methods can be tackled by using a robotic platform equipped with various sensors that can detect, navigate and tag the buried oil and gas pipelines. In UAE, the oil and gas pipelines are mostly buried under a berm, a raised trapezoidal structure made up of sand over the buried pipeline structure. The pipelines are buried under the berm either as (i) single pipeline buried in the middle of the berm or as (ii) two pipelines buried on the two edges of the berm. To conduct any external inspection of buried pipelines using a robotic platform, the accurate location of the buried pipeline has to be known beforehand. The proposed Autonomous Robotic Inspection System (ARIS) should have the capability to precisely locate the buried pipeline structure and navigate along with these structures without any fail/skid. A novel hierarchical controller based on a pipe-locator and ultrasonic sensor data is developed for ARIS for detection and navigation over the buried pipeline structures. The hierarchical controller consists of two modules: (i) pipe-locator based tracking controller, that allows the vehicle to autonomously navigate over the buried pipeline and (ii) a sonar-based anti-topple controller which provides an extra layer of protection for vehicle navigation under extreme conditions. An experimental setup, similar to the real buried pipeline condition was built in a lab environment. The autonomous tracking performance of ARIS was tested under various buried pipeline laying conditions. The results obtained show the ability of ARIS to track and navigate along the buried pipeline even in extreme conditions without any fall/skid.
{"title":"Autonomous Tracking Performance Analysis of Hierarchical Controller on Various Laying Conditions of Buried Oil and Gas Pipelines","authors":"Vidya Sudevan, Amit Shukla, Arjun Sharma, V. Bhadran, H. Karki","doi":"10.2118/197408-ms","DOIUrl":"https://doi.org/10.2118/197408-ms","url":null,"abstract":"\u0000 Middle Eastern countries have the most complex and extensive oil and gas pipeline network in the world and are expected to have a total length of 24066.9km of pipelines by 2022. Routine inspection and active maintenance of these structures thus have high priority in the oil and gas operations. Pigging, the commonly used internal inspection method is expensive and the need for pre-installation procedures for flawless pig operations makes it time-consuming. The external inspection is currently done manually by a group of operators who either drives or walks over the buried pipeline structures. The visual/sensor data collected using various handheld devices are then analyzed manually to identify/locate the possible anomalies. The accuracy of data collected and their analysis highly depends upon the experience of the operators. Also, the extreme environmental conditions like high temperature and uneven terrain make the manual inspection a tedious task. The challenges in the current manual inspection methods can be tackled by using a robotic platform equipped with various sensors that can detect, navigate and tag the buried oil and gas pipelines.\u0000 In UAE, the oil and gas pipelines are mostly buried under a berm, a raised trapezoidal structure made up of sand over the buried pipeline structure. The pipelines are buried under the berm either as (i) single pipeline buried in the middle of the berm or as (ii) two pipelines buried on the two edges of the berm. To conduct any external inspection of buried pipelines using a robotic platform, the accurate location of the buried pipeline has to be known beforehand. The proposed Autonomous Robotic Inspection System (ARIS) should have the capability to precisely locate the buried pipeline structure and navigate along with these structures without any fail/skid. A novel hierarchical controller based on a pipe-locator and ultrasonic sensor data is developed for ARIS for detection and navigation over the buried pipeline structures. The hierarchical controller consists of two modules: (i) pipe-locator based tracking controller, that allows the vehicle to autonomously navigate over the buried pipeline and (ii) a sonar-based anti-topple controller which provides an extra layer of protection for vehicle navigation under extreme conditions. An experimental setup, similar to the real buried pipeline condition was built in a lab environment. The autonomous tracking performance of ARIS was tested under various buried pipeline laying conditions. The results obtained show the ability of ARIS to track and navigate along the buried pipeline even in extreme conditions without any fall/skid.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78649558","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. Zayani, Dayang Nuriza Zaila M. Munir, N. Hooper, Kelvin Thian, M. Johan, Muhamad Zaki Amir Hussein, Rahmat Wibisono, Akram Arifin, M. Kadir, S. S. Shahril, Chidi Ogueri
In brownfield developments, prolonging the production life of the wells beyond the 30-year original well design life has been one of the challenges in managing well integrity. This challenge is often compromised by multiple tubing leaks or, in the worst case, by parted tubing caused by metal fatigue, erosion, and corrosion. The issue is often observed in many wells in the S field and usually occurs at a shallow depth between the tubing hanger and subsurface safety valve. The conventional through-tubing repair technique becomes increasingly difficult and ultimately tends to be unsuccessful. Moreover, with the challenge of low oil prices, a simple single-trip system, necessary to reduce costs and increase the success rate, is preferred. Several cost effective approaches to repair production tubing leaks have been available in the market for quite some time. These conventional methods (e.g., stackable slickline straddle, multi-run coiled tubing (CT) conveyed straddle, and tubing patches) come with basic tools, but require difficult manipulation to set and retrieve some of the assemblies, which are permanently installed, that may complicate future well abandonment. For wells with multiple leaks or where the completion tubing has been parted, complete replacement of completion tubing will be the only solution because of the severity of damage. This typically requires a workover rig or snubbing unit at both economically and operationally significant expense. It also typically results in a significant amount time required for well preparation, mobilization, and demobilization of the rig. In addition, the retrieval of this degree of corroded completion is not straightforward because it can come apart piece by piece, which will consume additional time. This paper describes the first customized, through-tubing hanger system installed at the lower master valve (LMV) of its kind. This unique repair method uses a coiled tubing-conveyed swellable packer, a hanging mechanism at the LMV, and through-tubing swellable packer elastomers at both top and bottom of the assembly. A description of the single-trip technology is presented, with a brief description of its engineering development and the installation procedure. The candidate selection process and installation procedure are discussed; information about the economics is provided to demonstrate that this type of repair was economically superior to a rig workover. This paper presents the successful field application of a new well intervention technique to repair multiple shallow leaks in production tubing in S field, an offshore field located in Malaysia. Effective teamwork among various parties through all phases, including engineering design, LMV fabrication, through-tubing hanger customization, swellability laboratory testing, and the execution phase, were key elements to the success of this pioneer project. By demonstrating the operational possibility and a low-cost alternative to an expensive rig worko
{"title":"An Integrated Solution to Repair Multiple Shallow Leaks in Production Tubing – A Unique Single Trip Well Intervention Technique","authors":"S. Zayani, Dayang Nuriza Zaila M. Munir, N. Hooper, Kelvin Thian, M. Johan, Muhamad Zaki Amir Hussein, Rahmat Wibisono, Akram Arifin, M. Kadir, S. S. Shahril, Chidi Ogueri","doi":"10.2118/197503-ms","DOIUrl":"https://doi.org/10.2118/197503-ms","url":null,"abstract":"\u0000 In brownfield developments, prolonging the production life of the wells beyond the 30-year original well design life has been one of the challenges in managing well integrity. This challenge is often compromised by multiple tubing leaks or, in the worst case, by parted tubing caused by metal fatigue, erosion, and corrosion. The issue is often observed in many wells in the S field and usually occurs at a shallow depth between the tubing hanger and subsurface safety valve. The conventional through-tubing repair technique becomes increasingly difficult and ultimately tends to be unsuccessful. Moreover, with the challenge of low oil prices, a simple single-trip system, necessary to reduce costs and increase the success rate, is preferred. Several cost effective approaches to repair production tubing leaks have been available in the market for quite some time. These conventional methods (e.g., stackable slickline straddle, multi-run coiled tubing (CT) conveyed straddle, and tubing patches) come with basic tools, but require difficult manipulation to set and retrieve some of the assemblies, which are permanently installed, that may complicate future well abandonment. For wells with multiple leaks or where the completion tubing has been parted, complete replacement of completion tubing will be the only solution because of the severity of damage. This typically requires a workover rig or snubbing unit at both economically and operationally significant expense. It also typically results in a significant amount time required for well preparation, mobilization, and demobilization of the rig. In addition, the retrieval of this degree of corroded completion is not straightforward because it can come apart piece by piece, which will consume additional time.\u0000 This paper describes the first customized, through-tubing hanger system installed at the lower master valve (LMV) of its kind. This unique repair method uses a coiled tubing-conveyed swellable packer, a hanging mechanism at the LMV, and through-tubing swellable packer elastomers at both top and bottom of the assembly. A description of the single-trip technology is presented, with a brief description of its engineering development and the installation procedure. The candidate selection process and installation procedure are discussed; information about the economics is provided to demonstrate that this type of repair was economically superior to a rig workover.\u0000 This paper presents the successful field application of a new well intervention technique to repair multiple shallow leaks in production tubing in S field, an offshore field located in Malaysia. Effective teamwork among various parties through all phases, including engineering design, LMV fabrication, through-tubing hanger customization, swellability laboratory testing, and the execution phase, were key elements to the success of this pioneer project. By demonstrating the operational possibility and a low-cost alternative to an expensive rig worko","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73128934","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 scope of the present paper is to show from concept to track record how iXblue maximized its clients financial and HSE results the use of DriX, an innovative yet seasoned Unmanned Surface Vehicle in the field of Survey and Energies industries. The overall approach was to create an offshore-going USV with data quality and speed of gathering as the two focal points. In order to do that, iXblue designed –A purely hydrodynamic shape with low water resistance and a higher tolerance to sea states–A gondola housing the sensors which provides the sensors with a perfect data gathering environment. I shall explain how iXblue suppressed the aeration effects on the sensors, and deeply dampened the vibrations and the USV radiated noise I will also show the audience our Launch and Recovery System, a corner stone for realistic Unmanned Operations at sea. The results were excellent. I shall show the audience how DriX exceeded expectations on the field by choosing past missions or trials and providing the audience with the results. These missions could be, for instance: Oil and Gas: Subsea Positioning: a Box-in in the Caspian Sea, performed in minutes; Renewable: Seabed Survey off the North Wales Coast in the UK in North Sea conditions, where DriX performed 3 times faster than a traditional asset; Survey: Multiple months survey in the Tonga islands in the Pacific Ocean along with a regular survey vessel; other missions within the Energy environment. The conclusions are that DriX is reliable, versatile and efficient. It has been designed with HSE and financial sense in mind. Almost two years in operations have shown that the goals have been reached, thanks to the guidance of a number of actors within the Energy Community. DriX is today operating daily around the world, and the scope of applications it does increases regularly. DriX ecosystem today encompasses number of capabilities that make it a relevant asset to own or rent. During the conference, I shall equally give a heads up on where we are planning to go in the next few months.
{"title":"Drix USV - Improving Safety and Margins Through Efficient Data Acquisition","authors":"Guillaume Eudeline","doi":"10.2118/197973-ms","DOIUrl":"https://doi.org/10.2118/197973-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The scope of the present paper is to show from concept to track record how iXblue maximized its clients financial and HSE results the use of DriX, an innovative yet seasoned Unmanned Surface Vehicle in the field of Survey and Energies industries.\u0000 \u0000 \u0000 \u0000 The overall approach was to create an offshore-going USV with data quality and speed of gathering as the two focal points. In order to do that, iXblue designed –A purely hydrodynamic shape with low water resistance and a higher tolerance to sea states–A gondola housing the sensors which provides the sensors with a perfect data gathering environment. I shall explain how iXblue suppressed the aeration effects on the sensors, and deeply dampened the vibrations and the USV radiated noise\u0000 I will also show the audience our Launch and Recovery System, a corner stone for realistic Unmanned Operations at sea.\u0000 \u0000 \u0000 \u0000 The results were excellent. I shall show the audience how DriX exceeded expectations on the field by choosing past missions or trials and providing the audience with the results. These missions could be, for instance: Oil and Gas: Subsea Positioning: a Box-in in the Caspian Sea, performed in minutes; Renewable: Seabed Survey off the North Wales Coast in the UK in North Sea conditions, where DriX performed 3 times faster than a traditional asset; Survey: Multiple months survey in the Tonga islands in the Pacific Ocean along with a regular survey vessel; other missions within the Energy environment. The conclusions are that DriX is reliable, versatile and efficient. It has been designed with HSE and financial sense in mind. Almost two years in operations have shown that the goals have been reached, thanks to the guidance of a number of actors within the Energy Community. DriX is today operating daily around the world, and the scope of applications it does increases regularly.\u0000 \u0000 \u0000 \u0000 DriX ecosystem today encompasses number of capabilities that make it a relevant asset to own or rent. During the conference, I shall equally give a heads up on where we are planning to go in the next few months.\u0000","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"69 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81419436","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}
N. Sukkee, T. Ketmalee, Nattapon Jalernsuk, Renaud Lemaire, P. Bandyopadhyay
Seismic well tie is a critical process to verify the time-depth relationship of a well. This process requires density and sonic transit time data. However, sonic logs are usually not acquired due to cost saving, unfavorable well path, or other operational issues. Attempts to generate synthetic logs by Gardner equation, porosity correlation, or depth correlation did not provide the required accuracy. Therefore, the goal of our project was to generate synthetic sonic logs using machine learning technique for seismic well ties. This paper will compare the different methods tested, compare the results and lists the advantages of using Machine Learning. This approach uses machine learning technique to create synthetic sonic logs. The machine learning model is trained to predict sonic log from other relevant logs. The model representativeness is confirmed by blind tests, which consists of two steps. The first step compares the synthetic sonic logs to the actual sonic logs. In the second step, four synthetic seismograms are generated from actual sonic, machine learning synthetic sonic, Gardner predicted sonic, and averaged constant sonic. The seismic well ties are compared between those four synthetic seismograms. Once the machine learning synthetic and actual logs show similar results, the model is deemed good and can be applied on wells that do not have sonic logs. The synthetic seismograms are then generated using synthetic sonic logs for all the wells that do not have actual sonic logs. The use of synthetic sonic logs gives us the ability to Generate synthetic seismogram to tie wells that do not have sonic dataReduce the number sonic data acquisition, saving time and moneyReduce the risk of long logging string getting stuck in the hole that would requires fishing operations and its associated cost.
{"title":"Application of Machine Learning to Estimate Sonic Data for Seismic Well Ties, Bongkot Field, Thailand","authors":"N. Sukkee, T. Ketmalee, Nattapon Jalernsuk, Renaud Lemaire, P. Bandyopadhyay","doi":"10.2118/197822-ms","DOIUrl":"https://doi.org/10.2118/197822-ms","url":null,"abstract":"\u0000 Seismic well tie is a critical process to verify the time-depth relationship of a well. This process requires density and sonic transit time data. However, sonic logs are usually not acquired due to cost saving, unfavorable well path, or other operational issues. Attempts to generate synthetic logs by Gardner equation, porosity correlation, or depth correlation did not provide the required accuracy. Therefore, the goal of our project was to generate synthetic sonic logs using machine learning technique for seismic well ties. This paper will compare the different methods tested, compare the results and lists the advantages of using Machine Learning.\u0000 This approach uses machine learning technique to create synthetic sonic logs. The machine learning model is trained to predict sonic log from other relevant logs. The model representativeness is confirmed by blind tests, which consists of two steps. The first step compares the synthetic sonic logs to the actual sonic logs. In the second step, four synthetic seismograms are generated from actual sonic, machine learning synthetic sonic, Gardner predicted sonic, and averaged constant sonic. The seismic well ties are compared between those four synthetic seismograms. Once the machine learning synthetic and actual logs show similar results, the model is deemed good and can be applied on wells that do not have sonic logs. The synthetic seismograms are then generated using synthetic sonic logs for all the wells that do not have actual sonic logs.\u0000 The use of synthetic sonic logs gives us the ability to Generate synthetic seismogram to tie wells that do not have sonic dataReduce the number sonic data acquisition, saving time and moneyReduce the risk of long logging string getting stuck in the hole that would requires fishing operations and its associated cost.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"9 8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78640861","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}
Managing severe to total lost circulation can present major challenges in naturally fractured formations. Particulate lost circulation materials (LCMs) have been used to manage lost circulation for many years; however, current LCMs are not efficient in terms of their size and application methods for curing severe to total losses, such as those encountered in highly fractured formations. Controlling severe to total lost circulation in naturally fractured/vugular formations has always been challenging, particularly in carbonate formations across the Middle East. In such situations, conventional particulate LCMs may not be effective. This paper presents a strategy and discussion for three types of contingency particulate LCMs that can be efficiently applied on location and have been shown to reduce drilling nonproductive time (NPT) before resorting to more difficult and time-consuming options, such as gunks/cement. The design of the innovative LCMs is based on the concept of a multimodal (MM) particle-size distribution (PSD) that can plug a range of fracture sizes. This paper discusses a strategy for applying three types of LCMs [engineered composite solutions (ECS) or one-sack solutions] that may potentially cure severe to total losses in upper/intermediate sections and in reservoirs (where acid solubility is desired). They perform efficiently compared to solutions that require mixing 6 to 10 components and require less inventory on the rig. The greatest advantage is that experimental variation of various component types and amounts has been previously tested in the laboratory before selecting the optimum formulation. In laboratory-based tests, each MM LCM has efficiently sealed 3,000 microns slotted discs. When they fail to perform on larger slotted discs (more than 3,000 microns and up to 9,800 microns in one case), supplemental materials have been defined (i.e., swelling polymer and/or reticulated foam) to increase the plugging efficiency for worst-case applications. ECS-1 is a MM, tough LCM that is applicable for severe losses in upper/intermediate holes where acid solubility is not necessary. Successful field applications in highly fractured carbonate formations in the Middle East are presented using the tough LCM on its own and in combination with a swelling polymer and a high aspect ratio fiber to cure total losses. ECS-2, a high fluid-loss squeeze LCM, can be used where ECS-1 (even with supplements) fails and in applications where acid solubility is not necessary. The uniqueness of this LCM is fine-sized reticulated foam in the sack. This paper presents successful field applications for the combinations of this high fluid loss squeeze LCM supplemented with larger reticulated foam. ECS-3 is a MM, acid-soluble LCM designed to perform similarly to ECS-1 but in a reservoir where acid solubility is desired. The three ECS strategies, along with the supplemental LCMs, might provide more technically efficient options for managing severe to
{"title":"Managing Lost Circulation in Highly Fractured, Vugular Formations: Engineering the LCM Design and Application","authors":"S. Savari, D. Whitfill","doi":"10.2118/197186-ms","DOIUrl":"https://doi.org/10.2118/197186-ms","url":null,"abstract":"\u0000 Managing severe to total lost circulation can present major challenges in naturally fractured formations. Particulate lost circulation materials (LCMs) have been used to manage lost circulation for many years; however, current LCMs are not efficient in terms of their size and application methods for curing severe to total losses, such as those encountered in highly fractured formations.\u0000 Controlling severe to total lost circulation in naturally fractured/vugular formations has always been challenging, particularly in carbonate formations across the Middle East. In such situations, conventional particulate LCMs may not be effective. This paper presents a strategy and discussion for three types of contingency particulate LCMs that can be efficiently applied on location and have been shown to reduce drilling nonproductive time (NPT) before resorting to more difficult and time-consuming options, such as gunks/cement.\u0000 The design of the innovative LCMs is based on the concept of a multimodal (MM) particle-size distribution (PSD) that can plug a range of fracture sizes. This paper discusses a strategy for applying three types of LCMs [engineered composite solutions (ECS) or one-sack solutions] that may potentially cure severe to total losses in upper/intermediate sections and in reservoirs (where acid solubility is desired). They perform efficiently compared to solutions that require mixing 6 to 10 components and require less inventory on the rig. The greatest advantage is that experimental variation of various component types and amounts has been previously tested in the laboratory before selecting the optimum formulation.\u0000 In laboratory-based tests, each MM LCM has efficiently sealed 3,000 microns slotted discs. When they fail to perform on larger slotted discs (more than 3,000 microns and up to 9,800 microns in one case), supplemental materials have been defined (i.e., swelling polymer and/or reticulated foam) to increase the plugging efficiency for worst-case applications.\u0000 ECS-1 is a MM, tough LCM that is applicable for severe losses in upper/intermediate holes where acid solubility is not necessary. Successful field applications in highly fractured carbonate formations in the Middle East are presented using the tough LCM on its own and in combination with a swelling polymer and a high aspect ratio fiber to cure total losses.\u0000 ECS-2, a high fluid-loss squeeze LCM, can be used where ECS-1 (even with supplements) fails and in applications where acid solubility is not necessary. The uniqueness of this LCM is fine-sized reticulated foam in the sack. This paper presents successful field applications for the combinations of this high fluid loss squeeze LCM supplemented with larger reticulated foam.\u0000 ECS-3 is a MM, acid-soluble LCM designed to perform similarly to ECS-1 but in a reservoir where acid solubility is desired.\u0000 The three ECS strategies, along with the supplemental LCMs, might provide more technically efficient options for managing severe to","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80367289","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 introduces an analytical approach for generating the inflow performance relationships (IPR) of different reservoirs depleted by different wellbore types at different conditions. The main focus of this paper is given to multiphase flow (oil, gas, water) and two-phase flow (oil, gas) during transient and pseudo-steady state flow conditions. The proposed approach presents new integrated models for the IPR that correlates the wellbore pressure with the multiphase total flow rate or the normalized pressure and rate by the bubble point pressure and single-phase flow rate at this pressure. These models consider the changes in reservoir fluid physical properties and reservoir relative permeabilities by coupling PVT data and relative permeability curves. The motivation of this study is reducing the uncertainty in the IPR of reservoirs undergoing the multiphase flow. Predicting multiphase IPRs may go throughout three tasks. The first is developing the pressure functions of reservoir mobility and total compressibility by developing several correlations for reservoir fluid properties such as oil, gas, and water formation volume factor as well as gas solubility in oil and water. Several correlations are needed also for relative permeability behavior of the three fluids with the pressure. These correlations can be generated by the multi-regression analysis of PVT data and relative permeability curves. The second represents developing the analytical models for the flow regimes that could be developed during the entire production life of the reservoirs. The single and multiphase flow IPRs for different flow regimes are predicted in the third task. The proposed IPR in this study is plotted between the wellbore pressure and the total flow rate at reservoir condition or the normalized reservoir pressure and flow rate. The observations obtained from this study are: 1) The proposed approach for the multiphase flow IPRs is not only time-variant but also depends on the flow condition whether transient or pseudo-steady state flow. 2) The IPR of the multiphase flow gives lower performance than the single-phase flow. 3) The IPR of the early time transient production is better than the late time pseudo-steady state production. 4) It is highly recommended to develop the models of fluid properties for each reservoir instead of using the models presented in the literature. The novel points presented in this paper are: 1) Introducing a new approach for the inflow performance relationships in the reservoirs experiencing multiphase flow and depleted by horizontal wells or multiple hydraulic fractures. 2) Introducing the pressure functions of the multiphase flow reservoir mobility and multiphase flow total reservoir compressibility that consider the changes in reservoir fluid properties and relative permeabilities with production time and pressure in constructing the IPRs.
{"title":"New Integrated Analytical Approach for Multiphase Inflow Performance Relationship","authors":"S. Al-Rbeawi","doi":"10.2118/197342-ms","DOIUrl":"https://doi.org/10.2118/197342-ms","url":null,"abstract":"\u0000 This paper introduces an analytical approach for generating the inflow performance relationships (IPR) of different reservoirs depleted by different wellbore types at different conditions. The main focus of this paper is given to multiphase flow (oil, gas, water) and two-phase flow (oil, gas) during transient and pseudo-steady state flow conditions. The proposed approach presents new integrated models for the IPR that correlates the wellbore pressure with the multiphase total flow rate or the normalized pressure and rate by the bubble point pressure and single-phase flow rate at this pressure. These models consider the changes in reservoir fluid physical properties and reservoir relative permeabilities by coupling PVT data and relative permeability curves. The motivation of this study is reducing the uncertainty in the IPR of reservoirs undergoing the multiphase flow.\u0000 Predicting multiphase IPRs may go throughout three tasks. The first is developing the pressure functions of reservoir mobility and total compressibility by developing several correlations for reservoir fluid properties such as oil, gas, and water formation volume factor as well as gas solubility in oil and water. Several correlations are needed also for relative permeability behavior of the three fluids with the pressure. These correlations can be generated by the multi-regression analysis of PVT data and relative permeability curves. The second represents developing the analytical models for the flow regimes that could be developed during the entire production life of the reservoirs. The single and multiphase flow IPRs for different flow regimes are predicted in the third task. The proposed IPR in this study is plotted between the wellbore pressure and the total flow rate at reservoir condition or the normalized reservoir pressure and flow rate.\u0000 The observations obtained from this study are: 1) The proposed approach for the multiphase flow IPRs is not only time-variant but also depends on the flow condition whether transient or pseudo-steady state flow. 2) The IPR of the multiphase flow gives lower performance than the single-phase flow. 3) The IPR of the early time transient production is better than the late time pseudo-steady state production. 4) It is highly recommended to develop the models of fluid properties for each reservoir instead of using the models presented in the literature.\u0000 The novel points presented in this paper are: 1) Introducing a new approach for the inflow performance relationships in the reservoirs experiencing multiphase flow and depleted by horizontal wells or multiple hydraulic fractures. 2) Introducing the pressure functions of the multiphase flow reservoir mobility and multiphase flow total reservoir compressibility that consider the changes in reservoir fluid properties and relative permeabilities with production time and pressure in constructing the IPRs.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86972136","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}
E. Barragan, Abdul Naser Al Mulla, M. Bazuhair, A. Alshalabi, R. Cornwall
A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production. Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B. The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone. An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.
{"title":"Innovative Application on Dual Oil Producer Completion: Gas Lift for Lower Zone and Natural Flow for Upper Zone Extends Oil Production in Giant Middle Eastern Oil Field","authors":"E. Barragan, Abdul Naser Al Mulla, M. Bazuhair, A. Alshalabi, R. Cornwall","doi":"10.2118/197486-ms","DOIUrl":"https://doi.org/10.2118/197486-ms","url":null,"abstract":"\u0000 A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production.\u0000 Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B.\u0000 The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone.\u0000 An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89942389","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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