One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction. The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure. The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment
{"title":"Geomechanical Assessment of Compaction Related Well Integrity Risks For A Large Field In Sultanate Of Oman","authors":"Mohammed Al-Aamri, S. Mahajan, H. Mukhaini","doi":"10.2118/197308-ms","DOIUrl":"https://doi.org/10.2118/197308-ms","url":null,"abstract":"\u0000 One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction.\u0000 The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure\u0000 In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure.\u0000 The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90791059","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}
Originally developed as an enhanced entertainment technology, advancements in augmented and virtual hardware catapulted the development and adoption of these tools for industrial applications and, more recently, the oilfield. These tools have vast use potential—from training to solution creation to operations. The benefits of newly developed applications for rigsite virtual mapping and holographic model viewing and the improvements they introduce for service provider/operator collaboration are discussed. Conventional methods for rig survey execution and optimization for separation solutions, which include solids control and waste management technologies, can be time consuming, technically challenging, and costly. This can be particularly true for offshore operations where weather, logistics, drilling programs, and environmental regulations can rapidly increase project complexity. Additionally, the equipment selection process commonly involves communication and collaboration with multiple subject matter experts (SMEs) and operator representatives globally in an iterative and labor-intensive process that lends itself to the opportunity for miscommunication and errors. The preliminary use of rigsite virtual mapping and holographic model viewer applications is to demonstrate improvements to cross-organizational collaboration. Using rigsite virtual mapping allows specialists to conduct a rapid wide area scan (RWAS) to accurately map the rig space to create fully functional and scaled three-dimensional (3D) models that can be used in augmented reality (AR) and virtual reality (VR) to develop more robust visualization of system design and placement. Using rigsite virtual mapping allows the separations solutions team to more safely, efficiently, and accurately measure and scan a rig space to achieve the optimal equipment orientation and integration. The improved visual assets enable better alignment with operator teams. Using the holographic model viewer allows 3D models of where separation equipment can be placed within the physical space at the rigsite or in the office. On location, rig surveys can be enhanced by enabling personnel to more effectively identify obstacles that might impede installation. For the office, the service provider and operators can more effectively discuss technologies and technology solutions using enhanced visualization. Bringing the technology "into the room" enables more dynamic solution creation and ideation. A renowned global research and consulting firm lists AR/VR as a major emerging technology trend that has the capability to influence how companies do business. The application of these technologies can revitalize remote engineering collaboration and personnel optimization and reduce service/product delivery costs. Already successfully introduced in other markets, AR/VR in the oilfield has the potential to expand rapidly and become an essential tool for more efficient operations.
{"title":"Augmented and Virtual Reality Applications for Separation Solutions Improve Service Provider-Operator Collaboration and Technology Placement","authors":"Mark Stephen, S. Clarke, Ketan Kapila","doi":"10.2118/197801-ms","DOIUrl":"https://doi.org/10.2118/197801-ms","url":null,"abstract":"Originally developed as an enhanced entertainment technology, advancements in augmented and virtual hardware catapulted the development and adoption of these tools for industrial applications and, more recently, the oilfield. These tools have vast use potential—from training to solution creation to operations. The benefits of newly developed applications for rigsite virtual mapping and holographic model viewing and the improvements they introduce for service provider/operator collaboration are discussed. Conventional methods for rig survey execution and optimization for separation solutions, which include solids control and waste management technologies, can be time consuming, technically challenging, and costly. This can be particularly true for offshore operations where weather, logistics, drilling programs, and environmental regulations can rapidly increase project complexity. Additionally, the equipment selection process commonly involves communication and collaboration with multiple subject matter experts (SMEs) and operator representatives globally in an iterative and labor-intensive process that lends itself to the opportunity for miscommunication and errors. The preliminary use of rigsite virtual mapping and holographic model viewer applications is to demonstrate improvements to cross-organizational collaboration. Using rigsite virtual mapping allows specialists to conduct a rapid wide area scan (RWAS) to accurately map the rig space to create fully functional and scaled three-dimensional (3D) models that can be used in augmented reality (AR) and virtual reality (VR) to develop more robust visualization of system design and placement. Using rigsite virtual mapping allows the separations solutions team to more safely, efficiently, and accurately measure and scan a rig space to achieve the optimal equipment orientation and integration. The improved visual assets enable better alignment with operator teams. Using the holographic model viewer allows 3D models of where separation equipment can be placed within the physical space at the rigsite or in the office. On location, rig surveys can be enhanced by enabling personnel to more effectively identify obstacles that might impede installation. For the office, the service provider and operators can more effectively discuss technologies and technology solutions using enhanced visualization. Bringing the technology \"into the room\" enables more dynamic solution creation and ideation. A renowned global research and consulting firm lists AR/VR as a major emerging technology trend that has the capability to influence how companies do business. The application of these technologies can revitalize remote engineering collaboration and personnel optimization and reduce service/product delivery costs. Already successfully introduced in other markets, AR/VR in the oilfield has the potential to expand rapidly and become an essential tool for more efficient operations.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79794885","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Bermudez, Mahamat Habib Abdelkerim Doutoum, B. A. Azizi, M. Nour, R. Medina, Hesham Bereikaa, M. C. Rocha, M. Nasrallah
While drilling through the initial section of extended reach drill (ERD) wells in Abu Dhabi where the trajectory requires a high inclination across a recognized loss zone various options were required to be assessed to maximize efficiency while balancing risks. Factors such as loss rate, capability of mixing fluid, necessary density to help prevent flow from a shallow water-bearing zone, and rig time, where all necessary and key factors to consider in the design process. For this UAE field with common losses in the surface casing, brine capping was determined the best solution to continue drilling without generating nonproductive time or creating a possible wellbore instability issue when unable to keep up with building mud to offset mud losses. For wells with a higher inclination angle, when the loss rate reached the point where it was not possible to prepare the fluid to keep up with losses, it was necessary to identify a different solution to cure or significantly reduce the losses and enable the hole section to be drilled without potential operational risks. For vugular/fractured porosity formations, using tailored particle size materials was unsuccessful for curing the losses. Therefore, a unique solution was implemented by combining two different systems to battle the losses: a swelling polymer lost-circulation material (LCM) that hydrates and helps reduce flow velocity into the formation, followed by a shear-rate rheology-dependent cement system that is a tunable and tailored slurry with thixotropic properties, which stops losses and develops low compressive strength. With this combined solution, the drilling process was successfully resumed and completed. The usual loss rate for this particular vugular argillaceous limestone formation is between 600 and 800 bbl/hr while drilling. Once the solution was successfully implemented, losses were reduced to 15 bbl/hr. The technique was performed on a second well, applying the lessons learned from the first attempt, and the unique solution achieved a dramatic reduction of losses to 2 to 6 bbl/hr. The cost and effectiveness of the treatment demonstrated that this solution is best for optimizing the drilling process for this particular condition. Applying a swelling polymer LCM and the shear-rate rheology-dependent cement system cured losses for an argillaceous limestone formation with fractured/vugular porosity. It is the first global application of this combined solution.
{"title":"Combined Solution for Lost Circulation Treatment to Successfully Drill Through Naturally Fractured Vugular Porosity Formation on ERD Wells in the UAE","authors":"R. Bermudez, Mahamat Habib Abdelkerim Doutoum, B. A. Azizi, M. Nour, R. Medina, Hesham Bereikaa, M. C. Rocha, M. Nasrallah","doi":"10.2118/197509-ms","DOIUrl":"https://doi.org/10.2118/197509-ms","url":null,"abstract":"\u0000 While drilling through the initial section of extended reach drill (ERD) wells in Abu Dhabi where the trajectory requires a high inclination across a recognized loss zone various options were required to be assessed to maximize efficiency while balancing risks. Factors such as loss rate, capability of mixing fluid, necessary density to help prevent flow from a shallow water-bearing zone, and rig time, where all necessary and key factors to consider in the design process.\u0000 For this UAE field with common losses in the surface casing, brine capping was determined the best solution to continue drilling without generating nonproductive time or creating a possible wellbore instability issue when unable to keep up with building mud to offset mud losses. For wells with a higher inclination angle, when the loss rate reached the point where it was not possible to prepare the fluid to keep up with losses, it was necessary to identify a different solution to cure or significantly reduce the losses and enable the hole section to be drilled without potential operational risks.\u0000 For vugular/fractured porosity formations, using tailored particle size materials was unsuccessful for curing the losses. Therefore, a unique solution was implemented by combining two different systems to battle the losses: a swelling polymer lost-circulation material (LCM) that hydrates and helps reduce flow velocity into the formation, followed by a shear-rate rheology-dependent cement system that is a tunable and tailored slurry with thixotropic properties, which stops losses and develops low compressive strength. With this combined solution, the drilling process was successfully resumed and completed.\u0000 The usual loss rate for this particular vugular argillaceous limestone formation is between 600 and 800 bbl/hr while drilling. Once the solution was successfully implemented, losses were reduced to 15 bbl/hr. The technique was performed on a second well, applying the lessons learned from the first attempt, and the unique solution achieved a dramatic reduction of losses to 2 to 6 bbl/hr. The cost and effectiveness of the treatment demonstrated that this solution is best for optimizing the drilling process for this particular condition.\u0000 Applying a swelling polymer LCM and the shear-rate rheology-dependent cement system cured losses for an argillaceous limestone formation with fractured/vugular porosity. It is the first global application of this combined solution.","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":"78649318","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}
Sultan Dahi Al-Hassani, I. Altameemi, S. Ahmed, O. Khan, Mariam Khaleel Al Hammadi, H. Zakaria, T. Saqib, W. Fernandes, S. Potshangbam, K. Saravanakumar, S. Hassan
Undeveloped reservoirs poses many uncertainties in terms of reservoir structural control and inherent properties and as a result integrated fit for purpose engineering and technology plays a vital role to drill, appraise and complete a well successfully. While Maximum Reservoir Contact (MRC) wells show promise in increased deliverability, sustainability and cumulative recovery, the risk of high cost, reduced well life and sustainability issues can become real if the well is not planned, executed and appraised properly. This paper focuses on the integrated multi-disciplinary approach between Reservoir Engineering, Petroleum Engineering, Drilling and Geoscience functions to achieve MRC of 8,500 ft. in two sublayers of 3 ft. each while mapping and avoiding any potential risk for water zones. Data acquisition pertaining to reservoir characterization, fracture and fault identification was planned to enhance this undeveloped reservoir understanding and to optimize lower completion design. 3D real-time multiwell reservoir modelling and updating capabilities with appropriate LWD measurements for Proactive Geosteering and Formation Evaluation was planned. Based on forward response model from offset well data along with drilling engineering and data acquisition requirements, an LWD suite consisting of RSS, Gamma Ray Image, High Resolution Resistivity Image (Fracture and Fault identification), NMR (both Total and Partial Porosities, and T2 Distribution) along with a Deep Azimuthal Resistivity measurement for early detection and avoidance of conductive/water zones was utilized. Achieved a field record of the longest drain drilled with 8,500 ft. of MRC. The fit for purpose real time LWD measurements enabled successful placement of the lower completion and blanking the risk zones for pro-longed sustainable production. Identification of fracture zones in real time helped in optimizing the completion plan while drilling. Based on this well's results, it is established that replicating the same practice could positively affect the overall Field Development potential. The same technique is planned for the future development of undeveloped reservoirs in this field.
{"title":"Successful Appraisal of Maximum Reservoir Contact Well in an Undeveloped Reservoir Through Well Construction and Integrated Fit for Purpose Engineering & Technology","authors":"Sultan Dahi Al-Hassani, I. Altameemi, S. Ahmed, O. Khan, Mariam Khaleel Al Hammadi, H. Zakaria, T. Saqib, W. Fernandes, S. Potshangbam, K. Saravanakumar, S. Hassan","doi":"10.2118/197120-ms","DOIUrl":"https://doi.org/10.2118/197120-ms","url":null,"abstract":"\u0000 Undeveloped reservoirs poses many uncertainties in terms of reservoir structural control and inherent properties and as a result integrated fit for purpose engineering and technology plays a vital role to drill, appraise and complete a well successfully. While Maximum Reservoir Contact (MRC) wells show promise in increased deliverability, sustainability and cumulative recovery, the risk of high cost, reduced well life and sustainability issues can become real if the well is not planned, executed and appraised properly.\u0000 This paper focuses on the integrated multi-disciplinary approach between Reservoir Engineering, Petroleum Engineering, Drilling and Geoscience functions to achieve MRC of 8,500 ft. in two sublayers of 3 ft. each while mapping and avoiding any potential risk for water zones. Data acquisition pertaining to reservoir characterization, fracture and fault identification was planned to enhance this undeveloped reservoir understanding and to optimize lower completion design.\u0000 3D real-time multiwell reservoir modelling and updating capabilities with appropriate LWD measurements for Proactive Geosteering and Formation Evaluation was planned. Based on forward response model from offset well data along with drilling engineering and data acquisition requirements, an LWD suite consisting of RSS, Gamma Ray Image, High Resolution Resistivity Image (Fracture and Fault identification), NMR (both Total and Partial Porosities, and T2 Distribution) along with a Deep Azimuthal Resistivity measurement for early detection and avoidance of conductive/water zones was utilized.\u0000 Achieved a field record of the longest drain drilled with 8,500 ft. of MRC. The fit for purpose real time LWD measurements enabled successful placement of the lower completion and blanking the risk zones for pro-longed sustainable production. Identification of fracture zones in real time helped in optimizing the completion plan while drilling. Based on this well's results, it is established that replicating the same practice could positively affect the overall Field Development potential. The same technique is planned for the future development of undeveloped reservoirs in this field.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80189002","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. I. Latief, S. Syofyan, I. Romanov, R. Valerio, Tariq Ali Al Shabibi
This study elaborates the evolving techniques implemented to address challenge of thin oil rim (5 to 10-ft) development in relatively thick reservoir-Z (90-ft thickness). The issues are related to the presence of gas cap, active bottom aquifer, and presence of high permeability streak at the top 4-6 ft. of reservoir layer. Thin dense layer (1-2 ft.) present inside the high-K streak and underneath the layer, reservoir properties drop significantly (ca. 2-permeability order). Log signature markedly influenced by the rock property contrast and unable to differentiate fluid types. The oil-water contact varies between wells, driven more by the rock-type contrast rather than structural/depth position. Horizontal wells are implemented and deliver sustainable oil production for all reservoirs in the field except for the Reservoir-Z. Due to its complexity, no horizontal wells drilled in the early production scheme (EPS) delivered any oil from the respective reservoir. The wells were mis-placed at either gas cap and/or aquifer leg. The subsequent development implemented cased and perforated completion with 60deg. inclination along reservoir interval to overcome well placement challenge. These wells delivered sub-optimal result due to high-drawdown (limited entry of perforated interval) and suffered from early gas and water breakthrough. Accordingly, well configuration is improved by having 85deg. inclination along reservoir section. It lengthens oil column penetration and facilitate longer perforation interval but inefficient due to the long-wasted interval inside the transition zone. Ultimately, in perspective of efficiency, an ambitious goal was set to drill horizontal wells along the peripheral oil rim. Materializing the goal practically left no room for error in well placement. Meanwhile, the field has cluster-based drilling, implying long step-out/ departure and some degree of wellbore survey uncertainty (1σ of trajectory uncertainty ca. 30 ft.). A comprehensive program was prepared to tackle the challenges. This subsume: Feasibility evaluation of deep azimuthal resistivity tool usage (forward model). Pilot hole and relevant data acquisition (fluid analyzer/sampling). Update of deep azimuthal resistivity forward model with the pilot hole result. Geosteering and risk mitigation plan. The pilot hole result met its very objective, i.e.: delineating the areal outline of GOC around the horizontal target location and provide the exact stratigraphic target for horizontal well placement. It is 2-3 ft TST target below thin dense act as baffle toward high-K streak layer. Below this stratigraphic target, water saturation (Sw) increases abruptly above 45%. The deep azimuthal and at-bit resistivity tool was used to geosteer the well and successfully delivered 2000 ft. section of dry oil without any crossing to the high-K layer. After the failure of the early horizontal wells, it becomes dogma that placing horizontal section along oil column of reservoir-Z
{"title":"A Strategic Approach to Address Challenge of Complex-Thin Oil Rim Development","authors":"A. I. Latief, S. Syofyan, I. Romanov, R. Valerio, Tariq Ali Al Shabibi","doi":"10.2118/197385-ms","DOIUrl":"https://doi.org/10.2118/197385-ms","url":null,"abstract":"\u0000 This study elaborates the evolving techniques implemented to address challenge of thin oil rim (5 to 10-ft) development in relatively thick reservoir-Z (90-ft thickness). The issues are related to the presence of gas cap, active bottom aquifer, and presence of high permeability streak at the top 4-6 ft. of reservoir layer. Thin dense layer (1-2 ft.) present inside the high-K streak and underneath the layer, reservoir properties drop significantly (ca. 2-permeability order). Log signature markedly influenced by the rock property contrast and unable to differentiate fluid types. The oil-water contact varies between wells, driven more by the rock-type contrast rather than structural/depth position.\u0000 Horizontal wells are implemented and deliver sustainable oil production for all reservoirs in the field except for the Reservoir-Z. Due to its complexity, no horizontal wells drilled in the early production scheme (EPS) delivered any oil from the respective reservoir. The wells were mis-placed at either gas cap and/or aquifer leg. The subsequent development implemented cased and perforated completion with 60deg. inclination along reservoir interval to overcome well placement challenge. These wells delivered sub-optimal result due to high-drawdown (limited entry of perforated interval) and suffered from early gas and water breakthrough.\u0000 Accordingly, well configuration is improved by having 85deg. inclination along reservoir section. It lengthens oil column penetration and facilitate longer perforation interval but inefficient due to the long-wasted interval inside the transition zone. Ultimately, in perspective of efficiency, an ambitious goal was set to drill horizontal wells along the peripheral oil rim. Materializing the goal practically left no room for error in well placement. Meanwhile, the field has cluster-based drilling, implying long step-out/ departure and some degree of wellbore survey uncertainty (1σ of trajectory uncertainty ca. 30 ft.).\u0000 A comprehensive program was prepared to tackle the challenges. This subsume:\u0000 Feasibility evaluation of deep azimuthal resistivity tool usage (forward model). Pilot hole and relevant data acquisition (fluid analyzer/sampling). Update of deep azimuthal resistivity forward model with the pilot hole result. Geosteering and risk mitigation plan.\u0000 The pilot hole result met its very objective, i.e.: delineating the areal outline of GOC around the horizontal target location and provide the exact stratigraphic target for horizontal well placement. It is 2-3 ft TST target below thin dense act as baffle toward high-K streak layer. Below this stratigraphic target, water saturation (Sw) increases abruptly above 45%. The deep azimuthal and at-bit resistivity tool was used to geosteer the well and successfully delivered 2000 ft. section of dry oil without any crossing to the high-K layer.\u0000 After the failure of the early horizontal wells, it becomes dogma that placing horizontal section along oil column of reservoir-Z ","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76399749","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}
Inflow tracer technology is a proven, risk-free and cost-effective method for continuous well and reservoir monitoring. To enable steady-state inflow assessment in real time, RESMAN has recently developed a new generation of Realtime Tracer technology. After a few years extensive research and development, this patented technology has been recently piloted successfully. This paper describes the different aspects of this new technology for the first time and present the results of the pilot. The Realtime Tracer technology consists of intelligent chemical tracers released by autonomous and wireless downhole injection tools and an in-line optical device at surface, which is retrievable and insertable during operation, for real time measurement of tracer signal. Upon injection, the intelligent tracers partition into the fluid phases, e.g. water tracer goes to water phase and oil tracer to oil phase, and subsequently the tracer molecules are transported to surface according to the velocity of fluids. At surface an automated measurement method with high sampling frequency, up to 0.1 second, ensures capturing all the tracer features with high resolution. The measured tracer signal is simultaneously processed in real time, by applying a dedicated computational algorithm, so that the results of test can be ready shortly after finishing the tests. The Realtime Tracer pilot was conducted in an onshore, vertical and water test well in Norway. The downhole injection tools were placed in two locations along the well while the in-line probe was installed on the surface line. Based on the results from the pilot, all aspects of this technology have been successfully validated and verified. This includes the performance of injection tools, detection of different tracers, measurement method and device, the dedicated software and its incorporated algorithm as well as inflow assessment to allow for relative production estimation. The Realtime Tracer technology provides significant improvement in tracer technology as it enhances different aspects of the existing tracer technologies through testing a well during production (no need for well shut-in and thus no production loss), less human interaction by real time measurement with high frequency (no need for manual sampling), quick delivery of results etc. The latter, for example, will improve decision-making process significantly, enabling production engineers to optimise the well performance and helps them to mitigate the problems as early as possible.
{"title":"Novel Realtime Tracer Technology for Continuous Well and Reservoir Monitoring","authors":"E. Nikjoo","doi":"10.2118/197691-ms","DOIUrl":"https://doi.org/10.2118/197691-ms","url":null,"abstract":"\u0000 Inflow tracer technology is a proven, risk-free and cost-effective method for continuous well and reservoir monitoring. To enable steady-state inflow assessment in real time, RESMAN has recently developed a new generation of Realtime Tracer technology. After a few years extensive research and development, this patented technology has been recently piloted successfully. This paper describes the different aspects of this new technology for the first time and present the results of the pilot.\u0000 The Realtime Tracer technology consists of intelligent chemical tracers released by autonomous and wireless downhole injection tools and an in-line optical device at surface, which is retrievable and insertable during operation, for real time measurement of tracer signal.\u0000 Upon injection, the intelligent tracers partition into the fluid phases, e.g. water tracer goes to water phase and oil tracer to oil phase, and subsequently the tracer molecules are transported to surface according to the velocity of fluids. At surface an automated measurement method with high sampling frequency, up to 0.1 second, ensures capturing all the tracer features with high resolution. The measured tracer signal is simultaneously processed in real time, by applying a dedicated computational algorithm, so that the results of test can be ready shortly after finishing the tests.\u0000 The Realtime Tracer pilot was conducted in an onshore, vertical and water test well in Norway. The downhole injection tools were placed in two locations along the well while the in-line probe was installed on the surface line. Based on the results from the pilot, all aspects of this technology have been successfully validated and verified. This includes the performance of injection tools, detection of different tracers, measurement method and device, the dedicated software and its incorporated algorithm as well as inflow assessment to allow for relative production estimation.\u0000 The Realtime Tracer technology provides significant improvement in tracer technology as it enhances different aspects of the existing tracer technologies through testing a well during production (no need for well shut-in and thus no production loss), less human interaction by real time measurement with high frequency (no need for manual sampling), quick delivery of results etc. The latter, for example, will improve decision-making process significantly, enabling production engineers to optimise the well performance and helps them to mitigate the problems as early as possible.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74108456","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 oil and gas industry is increasingly looking toward data-driven solutions to boost performance, enhance efficiency and reduce costs. However, understanding such complex systems requires the consideration of data from multiple sources in real time. Digital Twin modelling is at the heart of the next generation of real-time production monitoring and optimization systems. Using the integration of data, simulation, and visualization of the entire operating company value chain, from the subsurface equipment to central processing facilities, it's a solution that maximizes production. Such a system for Real-time Production Optimization (RTPO) has been developed jointly by Siemens and Process Systems Enterprise by combining their XHQ and gPROMS Oilfield technology.
石油和天然气行业越来越多地寻求数据驱动的解决方案，以提高性能、提高效率和降低成本。然而，理解如此复杂的系统需要实时考虑来自多个来源的数据。数字孪生模型是下一代实时生产监控和优化系统的核心。通过整合从地下设备到中央处理设施的整个运营公司价值链的数据、模拟和可视化，该解决方案可以最大限度地提高产量。这种实时生产优化(RTPO)系统是由西门子和Process Systems Enterprise联合开发的，结合了XHQ和gPROMS油田技术。
{"title":"Real-Time Production Optimization - Applying a Digital Twin Model to Optimize the Entire Upstream Value Chain","authors":"B. Okhuijsen, K. Wade","doi":"10.2118/197693-ms","DOIUrl":"https://doi.org/10.2118/197693-ms","url":null,"abstract":"\u0000 The oil and gas industry is increasingly looking toward data-driven solutions to boost performance, enhance efficiency and reduce costs. However, understanding such complex systems requires the consideration of data from multiple sources in real time. Digital Twin modelling is at the heart of the next generation of real-time production monitoring and optimization systems. Using the integration of data, simulation, and visualization of the entire operating company value chain, from the subsurface equipment to central processing facilities, it's a solution that maximizes production. Such a system for Real-time Production Optimization (RTPO) has been developed jointly by Siemens and Process Systems Enterprise by combining their XHQ and gPROMS Oilfield technology.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86017783","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}
While the first subsea production system was installed in a shallow water environment (West Cameron field in Gulf of Mexico, by Shell in 55ft water depth, 1961), subsea development concept has been more synonymous with deepwater development. It has not been a development concept of choice for shallow water development in Middle East and Asia mainly due to the perception that it has higher life cycle cost and difficult to intervene. Subsea production concept can be a competitive option vis-à-vis topsides production concept in certain circumstances. More often than not, project economics dictates that development capital expenditure (CAPEX) requires to be as low as practicable; and pre-investment in the initial phase of the project development needs to be carefully managed to minimize its impact on CAPEX and net present value (NPV). Subsea production system are inherently fit-for-purpose and provide an ideal opportunity for project owners to assess the potential of the particular field before deciding to proceed with full-scale development in the subsequent phase. The fact that there is a large number of shallow-water subsea production systems installed and operated worldwide in the last 30 years provide sufficient track record, lifecycle cost and reliability data that could be used by field development and front end engineers in coming up with a feasible development concept with attractive NPV. Subsea production system in a shallow water environment is a proven concept predominantly due to the following factors: Provide alternative development option where fixed structures are not cost-effective:a) Where development costs may not justify the CAPEX for a platformb) Where brownfield expansion requires low well counts Optimize drilling program:a) If field reservoir areas are not reachable by deviated drilling from surface wells, producing hydrocarbon from multiple fixed structures might not be economically feasibleb) Subsea completion and production system offer better flexibility in term of field layout and well top-hole positioningAccelerated development cycle:a) Average 15-18 month to first oil from approval of Field Development Plan (FDP)b) Capital Investment is returned in a more timely mannerMinimize cost on extended well testing-Longer well testing operations from a floating vessel with a lower cost are possibleImproved health, safety and environmental (HSE) performance - Removes people from offshore, potential to reduce visual and environmental impact This paper will demonstrate that subsea development is a matured concept that can be attractive for shallow water applications.
{"title":"Cost-Effective Application of Subsea Production System as Field Development Concept in Shallow Water Environment","authors":"Mohamed Ajmel Jamaludin","doi":"10.2118/197604-ms","DOIUrl":"https://doi.org/10.2118/197604-ms","url":null,"abstract":"\u0000 While the first subsea production system was installed in a shallow water environment (West Cameron field in Gulf of Mexico, by Shell in 55ft water depth, 1961), subsea development concept has been more synonymous with deepwater development. It has not been a development concept of choice for shallow water development in Middle East and Asia mainly due to the perception that it has higher life cycle cost and difficult to intervene.\u0000 Subsea production concept can be a competitive option vis-à-vis topsides production concept in certain circumstances. More often than not, project economics dictates that development capital expenditure (CAPEX) requires to be as low as practicable; and pre-investment in the initial phase of the project development needs to be carefully managed to minimize its impact on CAPEX and net present value (NPV). Subsea production system are inherently fit-for-purpose and provide an ideal opportunity for project owners to assess the potential of the particular field before deciding to proceed with full-scale development in the subsequent phase.\u0000 The fact that there is a large number of shallow-water subsea production systems installed and operated worldwide in the last 30 years provide sufficient track record, lifecycle cost and reliability data that could be used by field development and front end engineers in coming up with a feasible development concept with attractive NPV.\u0000 Subsea production system in a shallow water environment is a proven concept predominantly due to the following factors: Provide alternative development option where fixed structures are not cost-effective:a) Where development costs may not justify the CAPEX for a platformb) Where brownfield expansion requires low well counts Optimize drilling program:a) If field reservoir areas are not reachable by deviated drilling from surface wells, producing hydrocarbon from multiple fixed structures might not be economically feasibleb) Subsea completion and production system offer better flexibility in term of field layout and well top-hole positioningAccelerated development cycle:a) Average 15-18 month to first oil from approval of Field Development Plan (FDP)b) Capital Investment is returned in a more timely mannerMinimize cost on extended well testing-Longer well testing operations from a floating vessel with a lower cost are possibleImproved health, safety and environmental (HSE) performance - Removes people from offshore, potential to reduce visual and environmental impact\u0000 This paper will demonstrate that subsea development is a matured concept that can be attractive for shallow water applications.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87832666","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}
Praveen Bangari, Krishna E. Nangare, Khamis Humaid Al Mazrouei
Improved plant reliability is one of the major business drivers for any organization in today's competitive environment. The goals of reducing downtime and moving to a more proactive maintenance strategy requires commitment to put into place intelligent maintenance and repair practices in order to identify the root cause of unplanned shutdowns and take the necessary steps to prevent future occurrences. ADNOC Onshore has developed a solution with the combination of subject matter expert analysis and available real-time data from Plant Historian (OSI PI). Rotating equipment's emerging problems can be traced through condition monitoring parameters changes. When these parameters are available for online trending along with historical data, we can perform regression and correlation analysis to find out relations between any two or multiple parameters. This solution works 24X7 on Plant Historian and identify certain conditions scripted on Plant Historian on real time basis and will generate emails to relevant subject matter expert's for further actions. These proactive email notifications cover the information such as, failure mode of the machines and relevant parameter profile/cause and effect with the required actions defined in Reliability Centered Maintenance based philosophy. This solution also includes the integration of Plant Historian with Asset Management System. This helps the operators for timely capturing the START/STOP events generated by the rotating equipment's into Asset Management System and also helps to generate the equipment's Availability & Reliability KPI's. This is one step towards the implementation of Artificial Intelligence (AI) using machine learning techniques based on the available parameter where basically invents/incident/symptoms are developed affecting the equipment/plant production and availability that are captured without human interventions. This has benefited ADNOC Onshore to address various issues on rotating equipment and they have been attended proactively to increase reliability/availability/maintainability of equipment's towards business mission and goals. Purpose of this paper is to show how intelligent diagnostic performed on available dynamic/design data from past, present for operational/condition monitoring parameters for rotating machines will be beneficial to trend and predict the performance deterioration. Identifying any developing abnormal condition before it reaches to alarm/trip condition and bringing it to the relevant expert notice is prime purpose of this paper. Maintenance management is generally evolved as the digital data availability increases with the implementation of digital solutions such for real-time data acquisition and storage. Many companies implement solutions for real-time data acquisition and storage but still maintenance strategy evaluation towards latest philosophies is on a lagging mode. In order to get maximum advantage, both maintenance strategy and digital data usa
{"title":"Improving Equipment Reliability and Availability through Real-time Data","authors":"Praveen Bangari, Krishna E. Nangare, Khamis Humaid Al Mazrouei","doi":"10.2118/197347-ms","DOIUrl":"https://doi.org/10.2118/197347-ms","url":null,"abstract":"\u0000 Improved plant reliability is one of the major business drivers for any organization in today's competitive environment. The goals of reducing downtime and moving to a more proactive maintenance strategy requires commitment to put into place intelligent maintenance and repair practices in order to identify the root cause of unplanned shutdowns and take the necessary steps to prevent future occurrences.\u0000 ADNOC Onshore has developed a solution with the combination of subject matter expert analysis and available real-time data from Plant Historian (OSI PI). Rotating equipment's emerging problems can be traced through condition monitoring parameters changes. When these parameters are available for online trending along with historical data, we can perform regression and correlation analysis to find out relations between any two or multiple parameters. This solution works 24X7 on Plant Historian and identify certain conditions scripted on Plant Historian on real time basis and will generate emails to relevant subject matter expert's for further actions. These proactive email notifications cover the information such as, failure mode of the machines and relevant parameter profile/cause and effect with the required actions defined in Reliability Centered Maintenance based philosophy. This solution also includes the integration of Plant Historian with Asset Management System. This helps the operators for timely capturing the START/STOP events generated by the rotating equipment's into Asset Management System and also helps to generate the equipment's Availability & Reliability KPI's. This is one step towards the implementation of Artificial Intelligence (AI) using machine learning techniques based on the available parameter where basically invents/incident/symptoms are developed affecting the equipment/plant production and availability that are captured without human interventions. This has benefited ADNOC Onshore to address various issues on rotating equipment and they have been attended proactively to increase reliability/availability/maintainability of equipment's towards business mission and goals.\u0000 Purpose of this paper is to show how intelligent diagnostic performed on available dynamic/design data from past, present for operational/condition monitoring parameters for rotating machines will be beneficial to trend and predict the performance deterioration. Identifying any developing abnormal condition before it reaches to alarm/trip condition and bringing it to the relevant expert notice is prime purpose of this paper.\u0000 \u0000 \u0000 Maintenance management is generally evolved as the digital data availability increases with the implementation of digital solutions such for real-time data acquisition and storage. Many companies implement solutions for real-time data acquisition and storage but still maintenance strategy evaluation towards latest philosophies is on a lagging mode. In order to get maximum advantage, both maintenance strategy and digital data usa","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91311730","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}
Ayman Alkhalaf, O. Isichei, N. Ansari, Rashad Milad
In this study, we aim to demonstrate how machine learning can empower computational models that can predict the flow rate of a given well. Given current real-time data and periodic well tests, this new method computes flow rates using data-driven model. The computational model is based on analyzing the relations and trends in historical data. Relational databases include huge amounts of data that have been accumulated throughout decades. In addition, there is a large number of incoming operational data points every second that gives a lot of insight about the current status, performance, and health of many wells. The project aims to utilize this data to predict the flow rate of a given well. A variety of well attributes serve as inputs to the computational models that find the current flow rate. Artificial Neural Networks (ANN) were used in order to build these computational models. In addition, a grid search algorithm was used to fine-tune the parameters for the ANN for every single well. Building a single unique model for every well yielded the most accurate results. Wells that are data-rich performed better than wells with insufficient data. To further enhance the accuracy of the models, models are retrained after every incoming patch of real-time data. This retraining calibrates the models to constantly represent the true well performance and predict better. In practice, Flow rate prediction is used by production engineers to analyze the performance of a given well and to accelerate the process of well test verification. One of the main challenges in building unique models for every well is fine-tuning the parameters for the artificial neural networks, which can be a computationally intensive task. Parameter fine-tuning hasn't been discussed in previous literature regarding flow rate prediction. Therefore, our unique approach addresses the individuality of every well and builds models accordingly. This high-level of customization addresses the problem of under-fitting in ANN well models.
{"title":"Utilizing Machine Learning for a Data Driven Approach to Flow Rate Prediction","authors":"Ayman Alkhalaf, O. Isichei, N. Ansari, Rashad Milad","doi":"10.2118/197266-ms","DOIUrl":"https://doi.org/10.2118/197266-ms","url":null,"abstract":"\u0000 In this study, we aim to demonstrate how machine learning can empower computational models that can predict the flow rate of a given well. Given current real-time data and periodic well tests, this new method computes flow rates using data-driven model. The computational model is based on analyzing the relations and trends in historical data. Relational databases include huge amounts of data that have been accumulated throughout decades. In addition, there is a large number of incoming operational data points every second that gives a lot of insight about the current status, performance, and health of many wells. The project aims to utilize this data to predict the flow rate of a given well.\u0000 A variety of well attributes serve as inputs to the computational models that find the current flow rate. Artificial Neural Networks (ANN) were used in order to build these computational models. In addition, a grid search algorithm was used to fine-tune the parameters for the ANN for every single well. Building a single unique model for every well yielded the most accurate results. Wells that are data-rich performed better than wells with insufficient data. To further enhance the accuracy of the models, models are retrained after every incoming patch of real-time data. This retraining calibrates the models to constantly represent the true well performance and predict better. In practice, Flow rate prediction is used by production engineers to analyze the performance of a given well and to accelerate the process of well test verification. One of the main challenges in building unique models for every well is fine-tuning the parameters for the artificial neural networks, which can be a computationally intensive task. Parameter fine-tuning hasn't been discussed in previous literature regarding flow rate prediction. Therefore, our unique approach addresses the individuality of every well and builds models accordingly. This high-level of customization addresses the problem of under-fitting in ANN well models.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90283678","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：