For most offshore and tidal zolone oil development in North China, one of the major challenges of the industry is high drilling uncertainty and low reservoir encountered rate at the braided river delta and fluvial deposition environment with the common characters of thin sand channels, severe lateral change, unstable sand structure and low sand connectivity. Optimizing the wellbore placement inside the complex reservoir and depicting the sand with detailed information are gradually being critical to real time geosteering in these areas. Over the last decades, the continuous improvement of distance-to-boundary logging while drilling workflows has dramatically enhance the drilling efficiency of horizontal well. However, relatively short depth of detection (DOD) and low sensitivity to multi-layer environment still cannot meet the requirement of drilling under these complicated geologies. To reduce the geosteering uncertainty and enhance formation evaluation in complex environment, a new advancement in mapping-while-drilling electromagnetic propagation resistivity method, with the industry's first combination of axial, tilted and transverse antennas and significant software enhancements, made a momentous progress for complex reservoir geosteering and characterization. Compared to the previous generation, this service could provide: Larger depth of detection which doubled the previous generation. For one hand, larger DOD means earlier proactive strategy for the well position optimization; For the other one, enlarged vision also helps achieve whole delineation of the target sand channel and thus much better geological understanding for the reservoir.More sensitivity for anisotropy and local sedimentary character. Improved measurements set and enhanced software algorithm can visualize the detailed characteristics inside the sand channel. With its up-to-eight-layer resistivity reconstruction, the refined inversion exceeds the existing propagation resistivity answer product. Outstanding performance was observed during the implementation. The target sand channel of 6-7m thickness could be delineated clearly by the refined inversion. It not only depicted the whole picture the sand body, but also provided an earlier sign of structural fluctuation, which ensured the success and high oil recovery rate of the horizontal section. For the well with higher anisotropy or more local sedimentary features, comparing to the blur reflection of the previous method, this ultra-high-definition technology could provide a sophisticated vision of the shape, thickness, direction and resistivity property of the local thin layers and shaly block. Reliable evidence of both outline and inside characteristics of the sand channels improved the further well path design and geological understanding. The ultra-high-definition mapping-while-drilling technology opened the market of complex deposition environment drilling. It remarkably increased the reservoir encountered rate and
{"title":"Next Level of Complex Reservoir Geosteering: The New Generation of Ultra-High-Definition Directional Resistivity Propagation Method","authors":"Guoquan Zhao, Baoqiang Jin, Liuhe Yang, Wei Li, Junliang Zhou, Lili Zhang, Fei Wang, Haifeng Wang, Shuzhong Li, Zhongtiang Hu, Tianyun Xu, J. Dolan","doi":"10.2523/iptc-22208-ea","DOIUrl":"https://doi.org/10.2523/iptc-22208-ea","url":null,"abstract":"\u0000 For most offshore and tidal zolone oil development in North China, one of the major challenges of the industry is high drilling uncertainty and low reservoir encountered rate at the braided river delta and fluvial deposition environment with the common characters of thin sand channels, severe lateral change, unstable sand structure and low sand connectivity. Optimizing the wellbore placement inside the complex reservoir and depicting the sand with detailed information are gradually being critical to real time geosteering in these areas.\u0000 Over the last decades, the continuous improvement of distance-to-boundary logging while drilling workflows has dramatically enhance the drilling efficiency of horizontal well. However, relatively short depth of detection (DOD) and low sensitivity to multi-layer environment still cannot meet the requirement of drilling under these complicated geologies.\u0000 To reduce the geosteering uncertainty and enhance formation evaluation in complex environment, a new advancement in mapping-while-drilling electromagnetic propagation resistivity method, with the industry's first combination of axial, tilted and transverse antennas and significant software enhancements, made a momentous progress for complex reservoir geosteering and characterization.\u0000 Compared to the previous generation, this service could provide: Larger depth of detection which doubled the previous generation. For one hand, larger DOD means earlier proactive strategy for the well position optimization; For the other one, enlarged vision also helps achieve whole delineation of the target sand channel and thus much better geological understanding for the reservoir.More sensitivity for anisotropy and local sedimentary character. Improved measurements set and enhanced software algorithm can visualize the detailed characteristics inside the sand channel. With its up-to-eight-layer resistivity reconstruction, the refined inversion exceeds the existing propagation resistivity answer product.\u0000 Outstanding performance was observed during the implementation. The target sand channel of 6-7m thickness could be delineated clearly by the refined inversion. It not only depicted the whole picture the sand body, but also provided an earlier sign of structural fluctuation, which ensured the success and high oil recovery rate of the horizontal section.\u0000 For the well with higher anisotropy or more local sedimentary features, comparing to the blur reflection of the previous method, this ultra-high-definition technology could provide a sophisticated vision of the shape, thickness, direction and resistivity property of the local thin layers and shaly block. Reliable evidence of both outline and inside characteristics of the sand channels improved the further well path design and geological understanding.\u0000 The ultra-high-definition mapping-while-drilling technology opened the market of complex deposition environment drilling. It remarkably increased the reservoir encountered rate and","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76507841","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. A. Hassan, Jim Strand, A. Strømhaug, Lene Lykke Erichsen
Well Construction Automation is gradually becoming more prominent in oil & gas industry. It encompasses the application of digital technology in all aspects of well drilling and completion (i.e., automatic well design, digi-talization of downhole tools & surface equipment, remote monitoring, real time data transmission, and robotic rig systems). This paper presents a new workflow of Automatic Well Design, at a mere click of a computer mouse, using integrated cloud software. A software tool, named WellDesign, is used to demonstrate Automatic Well Design workflow. It utilizes net-works and cloud computers for data storage and collaboration and offers a set of Application Programming In-terfaces (APIs), enabling full automation, where whole or parts of the software can be operated by other com-puters. The software GUI can be accessed via any modern web browser across all kinds of computers (Win-dows, Macs) and any other smart devices (tablets, phones). Two automatic design workflows shall be illustrated in detail: Automatic Well Trajectories Automatic Casing Design
{"title":"1-Click Automatic Well Design Using Integrated Cloud Software","authors":"M. A. Hassan, Jim Strand, A. Strømhaug, Lene Lykke Erichsen","doi":"10.2523/iptc-22018-ms","DOIUrl":"https://doi.org/10.2523/iptc-22018-ms","url":null,"abstract":"\u0000 Well Construction Automation is gradually becoming more prominent in oil & gas industry. It encompasses the application of digital technology in all aspects of well drilling and completion (i.e., automatic well design, digi-talization of downhole tools & surface equipment, remote monitoring, real time data transmission, and robotic rig systems). This paper presents a new workflow of Automatic Well Design, at a mere click of a computer mouse, using integrated cloud software.\u0000 A software tool, named WellDesign, is used to demonstrate Automatic Well Design workflow. It utilizes net-works and cloud computers for data storage and collaboration and offers a set of Application Programming In-terfaces (APIs), enabling full automation, where whole or parts of the software can be operated by other com-puters. The software GUI can be accessed via any modern web browser across all kinds of computers (Win-dows, Macs) and any other smart devices (tablets, phones).\u0000 Two automatic design workflows shall be illustrated in detail:\u0000 Automatic Well Trajectories Automatic Casing Design","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"790 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89829759","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}
Carbon dioxide (CO2) capture, utilization, and storage is the best option for mitigating atmospheric emissions of CO2 and thereby controlling the greenhouse gas concentrations in the atmosphere. Despite the benefits, there have been a limited number of projects solely for CO2 sequestration being implemented. The industry is well-versed in gas injection in reservoir formation for pressure maintenance and improving oil recovery. However, there are striking differences between the injection of CO2 into depleted hydrocarbon reservoirs and the engineered storage of CO2. The differences and challenges are compounded when the storage site is karstified carbonate in offshore and bulk storage volume. It is paramount to know upfront that CO2 can be stored at a potential storage site and demonstrate that the site can meet required storage performance safety criteria. Comprehensive screening for site selection has been carried out for suitable CO2 storage sites in offshore Sarawak, Malaysia using geographical, geological, geophysical, geomechanical and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generating performance scenarios of the site. In addition, the geochemical interaction of CO2 with reservoir rock has been studied to understand possible changes that may occur during/after injection and their impact on injection processes/mechanisms. Novel 3-way coupled modelling of dynamic-geochemistry-geomechanics processes were carried out to study long-term dynamic behaviour and fate of CO2 in the formation. The 3-way coupled modelling helped to understand the likely state of injectant in future and the storage mechanism, i.e., structural, solubility, residual, and mineralized trapping. It also provided realistic storage capacity estimation, incorporating reservoir compaction and porosity/permeability changes. The study indicates deficient localized plastic shear strain in overburden flank fault whilst all the other flaws remained stable. The potential threat of leakage is minimal as target injection pressure is set at initial reservoir pressure, which is much lower than caprock breaching pressure during injection. Furthermore, it was found that the geochemical reaction impact is shallow and localized at the top of the reservoir, making the storage safe in the long term. The integrity of existing wells was evaluated for potential leakage and planned for a proper mitigation plan. Comprehensive measurement, monitoring, and verification (MMV) were also designed using state-of-art tools and dynamic simulation results. The understanding gaps are closed with additional technical work to improve technologies application and decrease the uncertainties. A comprehensive study for offshore CO2 storage projects identifying critical impacting elements is crucial for estimation, inje
{"title":"A Toolkit for Offshore Carbon Capture and Storage CCS","authors":"R. Tewari, C. Tan, M. Sedaralit","doi":"10.2523/iptc-22307-ms","DOIUrl":"https://doi.org/10.2523/iptc-22307-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) capture, utilization, and storage is the best option for mitigating atmospheric emissions of CO2 and thereby controlling the greenhouse gas concentrations in the atmosphere. Despite the benefits, there have been a limited number of projects solely for CO2 sequestration being implemented. The industry is well-versed in gas injection in reservoir formation for pressure maintenance and improving oil recovery. However, there are striking differences between the injection of CO2 into depleted hydrocarbon reservoirs and the engineered storage of CO2. The differences and challenges are compounded when the storage site is karstified carbonate in offshore and bulk storage volume.\u0000 It is paramount to know upfront that CO2 can be stored at a potential storage site and demonstrate that the site can meet required storage performance safety criteria. Comprehensive screening for site selection has been carried out for suitable CO2 storage sites in offshore Sarawak, Malaysia using geographical, geological, geophysical, geomechanical and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generating performance scenarios of the site. In addition, the geochemical interaction of CO2 with reservoir rock has been studied to understand possible changes that may occur during/after injection and their impact on injection processes/mechanisms. Novel 3-way coupled modelling of dynamic-geochemistry-geomechanics processes were carried out to study long-term dynamic behaviour and fate of CO2 in the formation.\u0000 The 3-way coupled modelling helped to understand the likely state of injectant in future and the storage mechanism, i.e., structural, solubility, residual, and mineralized trapping. It also provided realistic storage capacity estimation, incorporating reservoir compaction and porosity/permeability changes. The study indicates deficient localized plastic shear strain in overburden flank fault whilst all the other flaws remained stable. The potential threat of leakage is minimal as target injection pressure is set at initial reservoir pressure, which is much lower than caprock breaching pressure during injection. Furthermore, it was found that the geochemical reaction impact is shallow and localized at the top of the reservoir, making the storage safe in the long term. The integrity of existing wells was evaluated for potential leakage and planned for a proper mitigation plan. Comprehensive measurement, monitoring, and verification (MMV) were also designed using state-of-art tools and dynamic simulation results. The understanding gaps are closed with additional technical work to improve technologies application and decrease the uncertainties.\u0000 A comprehensive study for offshore CO2 storage projects identifying critical impacting elements is crucial for estimation, inje","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82227730","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}
Mikhail Tcibulskii, Ivan Trofimenko, Marat Yagudin, A. Lodin, Vladimir Khohryakov
Lost circulation (LC) is commonly encountered in drilling and cementing operations and can significantly contribute to non-productive time (NPT). An operator in the Kyumbinskoe Field faced this challenge in a fractured production section of the formation, and conventional LC solutions had been ineffective at achieving strict regulatory top of cement (TOC) requirements and satisfactory cement bonding. This paper describes the experience of utilizing foam cementing technology as a primary solution to solve a lost circulation issue on the project. For this project a foam cementing solution was designed to meet operational parameters for cementing a production casing in one stage (multi-stage tool was eliminated). Use of foam cementing technology helped to minimize losses experienced in all cementing operations previously on this project. CBL results were also improved. All Customer requirements were met: Planned Top Of Cement (TOC)Minimum losses during cementing operationsRig time savingImproving CBL results.
{"title":"First Ever Deployment of Production System Optimization Tool in Giant Carbonate Offshore Field in UAE - Laying the Foundation for Digital Oil Field","authors":"Mikhail Tcibulskii, Ivan Trofimenko, Marat Yagudin, A. Lodin, Vladimir Khohryakov","doi":"10.2523/iptc-22040-ms","DOIUrl":"https://doi.org/10.2523/iptc-22040-ms","url":null,"abstract":"\u0000 Lost circulation (LC) is commonly encountered in drilling and cementing operations and can significantly contribute to non-productive time (NPT). An operator in the Kyumbinskoe Field faced this challenge in a fractured production section of the formation, and conventional LC solutions had been ineffective at achieving strict regulatory top of cement (TOC) requirements and satisfactory cement bonding. This paper describes the experience of utilizing foam cementing technology as a primary solution to solve a lost circulation issue on the project. For this project a foam cementing solution was designed to meet operational parameters for cementing a production casing in one stage (multi-stage tool was eliminated).\u0000 Use of foam cementing technology helped to minimize losses experienced in all cementing operations previously on this project. CBL results were also improved. All Customer requirements were met: Planned Top Of Cement (TOC)Minimum losses during cementing operationsRig time savingImproving CBL results.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83548646","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}
Multiphase fluids are mixtures of oil, water, and gas. Roughly six out of every ten wells contain multiphase fluids with variations in the fluid makeup, rheology, and viscosity. They may also include small amounts of sand, paraffin, hydrates, and drilling cuttings. This necessitates local separation at the well site, which can require a significant footprint of process equipment infrastructure at or near each well site. Ever since oil production began, produced fluids have been transferred from the well to the storage or processing facility using reservoir pressures. This means the bottom hole pressures needed to be sufficient to not only get the fluid to the surface but also move it some distance on the surface through flow lines. In cases where reservoirs are either low energy or are characterized by rapid pressure depletion curves as is common in a number of unconventional plays, this can be problematic. In wells that are artificially produced with a down hole pump or other artificial lift equipment the pump must have sufficient pressure capability to bring the fluids to the surface and then move them some distance on the surface through a flow line. Additional pressure may also be required for the separation equipment at the end of the flow line.
{"title":"Multiphase Pumping with Progressive Cavity Pumps","authors":"M. Hester","doi":"10.2523/iptc-22277-ea","DOIUrl":"https://doi.org/10.2523/iptc-22277-ea","url":null,"abstract":"\u0000 Multiphase fluids are mixtures of oil, water, and gas. Roughly six out of every ten wells contain multiphase fluids with variations in the fluid makeup, rheology, and viscosity. They may also include small amounts of sand, paraffin, hydrates, and drilling cuttings. This necessitates local separation at the well site, which can require a significant footprint of process equipment infrastructure at or near each well site.\u0000 Ever since oil production began, produced fluids have been transferred from the well to the storage or processing facility using reservoir pressures. This means the bottom hole pressures needed to be sufficient to not only get the fluid to the surface but also move it some distance on the surface through flow lines. In cases where reservoirs are either low energy or are characterized by rapid pressure depletion curves as is common in a number of unconventional plays, this can be problematic.\u0000 In wells that are artificially produced with a down hole pump or other artificial lift equipment the pump must have sufficient pressure capability to bring the fluids to the surface and then move them some distance on the surface through a flow line. Additional pressure may also be required for the separation equipment at the end of the flow line.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"62 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86423030","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 carbon emissions has become a major responsibility for the oil and gas industry in a drive to ensure sustainable energy and create a clean environment. Therefore, governments, research centers, IOC’s and NOC’s are actively adopting new guidelines and inventing new technologies to safely circulate carbons. In this paper, the process of modeling CO2 sequestration in a deep saline aquifer will be discussed. Carbon dioxide can be safely stored indefinitely in subsurface geological formations by four trapping mechanisms; structural, residual, soluble, and mineral trapping. These four trapping mechanisms can take hundreds or thousands of years to happen. Furthermore, the oil and gas industry standard recommend that any technology used to store CO2 needs to demonstrate a storage capacity of 1000 years with less than 0.1 per-cent leakage potential per year. Therefore, modelling such process should capture any existing trapping mechanism, even if it happens after several hundreds of years, to ensure long-term secure storage of the CO2. Using our in-house simulator "GigaPOWERS", many sequestration scenarios were conducted to come up with a recommended guideline to maximize the volume of CO2 trapped in deep saline aquifers. This study used a giant synthetic anticline model with a variation in geological properties. The residual and soluble trapping mechanisms were captured through relative permeability hysteresis and extended water PVT tables respectively. Injecting CO2 into water aquifers is a dynamic process where drainage and imbibition cycles are likely to happen. Such processes cause the CO2 to be trapped in the middle of the pores as an immobile phase, which can be a favorable phenomenon maximizing the security of CO2 sequestration. Since CO2 is soluble in water, when it contacts the water phase it will form a carbonated water that is denser than water itself and migrates downward in a phenomenon known as "CO2 fingering". The CO2 solubility in water depends mainly on the salinity and temperature which both need to be accurately captured in the simulation model. Depending on the long-term objective of the sequestration project, the development strategy can be altered to maximize the outcome using the detailed simulation model. In this paper, the simulation best practices for modeling CO2 sequestration for maximum secure long-term storage (1000+ years) are suggested. Carbon dioxide, CO2, sequestration in deep saline aquifers is a well-known method to reduce carbon emissions. However, there is very little published literature on the simulation best practices for modeling the CO2 sequestration process. Therefore, this paper will be a pioneer to guide the industry for accurate simulation of such process.
{"title":"Modeling CO2 Sequestration in Deep Saline Aquifers – Best Practices","authors":"Hassan Alzayer, Tareq Zahrani, A. Shubbar","doi":"10.2523/iptc-22423-ea","DOIUrl":"https://doi.org/10.2523/iptc-22423-ea","url":null,"abstract":"\u0000 Managing carbon emissions has become a major responsibility for the oil and gas industry in a drive to ensure sustainable energy and create a clean environment. Therefore, governments, research centers, IOC’s and NOC’s are actively adopting new guidelines and inventing new technologies to safely circulate carbons. In this paper, the process of modeling CO2 sequestration in a deep saline aquifer will be discussed.\u0000 Carbon dioxide can be safely stored indefinitely in subsurface geological formations by four trapping mechanisms; structural, residual, soluble, and mineral trapping. These four trapping mechanisms can take hundreds or thousands of years to happen. Furthermore, the oil and gas industry standard recommend that any technology used to store CO2 needs to demonstrate a storage capacity of 1000 years with less than 0.1 per-cent leakage potential per year. Therefore, modelling such process should capture any existing trapping mechanism, even if it happens after several hundreds of years, to ensure long-term secure storage of the CO2. Using our in-house simulator \"GigaPOWERS\", many sequestration scenarios were conducted to come up with a recommended guideline to maximize the volume of CO2 trapped in deep saline aquifers.\u0000 This study used a giant synthetic anticline model with a variation in geological properties. The residual and soluble trapping mechanisms were captured through relative permeability hysteresis and extended water PVT tables respectively. Injecting CO2 into water aquifers is a dynamic process where drainage and imbibition cycles are likely to happen. Such processes cause the CO2 to be trapped in the middle of the pores as an immobile phase, which can be a favorable phenomenon maximizing the security of CO2 sequestration. Since CO2 is soluble in water, when it contacts the water phase it will form a carbonated water that is denser than water itself and migrates downward in a phenomenon known as \"CO2 fingering\". The CO2 solubility in water depends mainly on the salinity and temperature which both need to be accurately captured in the simulation model. Depending on the long-term objective of the sequestration project, the development strategy can be altered to maximize the outcome using the detailed simulation model. In this paper, the simulation best practices for modeling CO2 sequestration for maximum secure long-term storage (1000+ years) are suggested.\u0000 Carbon dioxide, CO2, sequestration in deep saline aquifers is a well-known method to reduce carbon emissions. However, there is very little published literature on the simulation best practices for modeling the CO2 sequestration process. Therefore, this paper will be a pioneer to guide the industry for accurate simulation of such process.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"2013 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86200415","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. Al-Sabea, A. Abu-Eida, M. Patra, M. AlEidi, G. Ambrosi, Nakul Khandelwal, Rishi Gaur, Khaled M. Matar, Abdulatif Al wazzan, J. Vasquez
Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for the efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. This paper highlights the successful application of an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant or emulsification by diesel. An acid stimulation job using a new innovative retarded acid system has been performed in a West Kuwait field well. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid "HCl") with a non-damaging retarding agent that allows deeper penetration of the live HCl acid into the formation, resulting in a more effective stimulation treatment. The retardation behavior testing includes dissolution experiments, compatibility testing, coreflood study, and corrosion rate testing (conducted at 200°F). The on-job implementation included the use of a packer to pinpoint fluid pumping (pre-flush) at the point of interest, followed by the customized novel retarded acid system for improving conductivity at perforations and effective reservoir stimulation. This acid system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and offers a cost-effective solution to cover a wide range of applications in matrix acid stimulation and high-temperature conditions that require a chemically retarded acid system. The application of this novel acid retarded system is a fit-for-purpose solution to optimize the return on investment by maximizing the well production and extending the lifetime of the treatment effect. This new system also offers excellent scale inhibition and iron control properties which eliminates the need for any acid remedial work, making it an economical approach over other conventional acid systems. The paper presents results obtained after stimulating the carbonate reservoir and describes the lessons learned from the job planning and execution phases, which can be considered as a best practice for application in similar challenges in other fields. Proper candidate selection, best available placement technique, and lab-tested formulation of novel retarded acid system resulted in achieving 1700 BOPD of oil production (27% higher than expected).
{"title":"Low Viscosity Polymer Free Acid Retarded System, a Novel Alternative to Emulsified Acid: Successful Application in West Kuwait Field","authors":"S. Al-Sabea, A. Abu-Eida, M. Patra, M. AlEidi, G. Ambrosi, Nakul Khandelwal, Rishi Gaur, Khaled M. Matar, Abdulatif Al wazzan, J. Vasquez","doi":"10.2523/iptc-22665-ms","DOIUrl":"https://doi.org/10.2523/iptc-22665-ms","url":null,"abstract":"\u0000 Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for the efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. This paper highlights the successful application of an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant or emulsification by diesel.\u0000 An acid stimulation job using a new innovative retarded acid system has been performed in a West Kuwait field well. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid \"HCl\") with a non-damaging retarding agent that allows deeper penetration of the live HCl acid into the formation, resulting in a more effective stimulation treatment. The retardation behavior testing includes dissolution experiments, compatibility testing, coreflood study, and corrosion rate testing (conducted at 200°F).\u0000 The on-job implementation included the use of a packer to pinpoint fluid pumping (pre-flush) at the point of interest, followed by the customized novel retarded acid system for improving conductivity at perforations and effective reservoir stimulation. This acid system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and offers a cost-effective solution to cover a wide range of applications in matrix acid stimulation and high-temperature conditions that require a chemically retarded acid system.\u0000 The application of this novel acid retarded system is a fit-for-purpose solution to optimize the return on investment by maximizing the well production and extending the lifetime of the treatment effect. This new system also offers excellent scale inhibition and iron control properties which eliminates the need for any acid remedial work, making it an economical approach over other conventional acid systems.\u0000 The paper presents results obtained after stimulating the carbonate reservoir and describes the lessons learned from the job planning and execution phases, which can be considered as a best practice for application in similar challenges in other fields. Proper candidate selection, best available placement technique, and lab-tested formulation of novel retarded acid system resulted in achieving 1700 BOPD of oil production (27% higher than expected).","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86458150","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}
L. Affede, R. Lorefice, Larissa Pinto Vieira, M. Giubertoni, Lorenzo Buzzi, G. Carpineta
During drilling of three exploration wells challenging conditions encountered, such as temperatures up to 180°C, interbedded highly reactive shales/silts, formation pressures which required mud weights up to 2.35 sg and narrow margin between pore and fracture gradients, posed a host of technical, logistical and cost challenges to Eni activities. These conditions required an accurate drilling fluids design to maximize operational efficiency and to minimize the risks related to such an extreme environment. Technical demands were particularly critical since the reactive shale formations had historically proved to be difficult to inhibit when drilled with Water Based Mud and might have caused swelling, tight hole, sticky wireline runs, bit-balling and accretion that could have resulted, among other issues, in low penetration rates (ROP). The formation nature coupled with ECD (Equivalent Circulation Density) constraints due to the high mud weight required to cope with high pore pressure, which also caused high mud rheology readings, were therefore the main limits to be overcome to achieve the well objectives. A tailored drilling fluid program was thus proposed which consisted of an inhibitive HPWBM (High Performance Water Based Mud) that could be converted to an HT-HPWBM, (High Temperature-High Performances Water Based Mud) while drilling, to cross the deeper and hotter sections of the well. This fluid was specifically engineered and optimized after each well in order to contain high concentration of a combination of monovalent salts to guarantee inhibition and reduce solids loading, dedicated polyamine shale inhibitor and fluid loss additives to minimize API/HPHT filtrate and filter cake thickness with the aim to reduce shale water invasion throughout the drilling campaign, graphite to minimizes fluid invasion and fracture propagation and ROP (Rate Of Penetration) enhancer continuously injected using dedicated pump to act as anti-balling and anti-accretion additive. The achieved results were drilling targets delivered safely, on time and with good overall fluid performances which either reduced or eliminated many of the challenges seen in offset wells, including: no barite sag, rheology stability, and stable long-term mud properties and wellbore conditions even during extended formation logs acquisitions. This paper covers the design, execution and accomplishments of the water-based drilling fluids employed on three HP/HT wells drilled, together with all of the lessons learned captured, highlighting the evolution of these systems to reach a step-change in terms of performances in such a harsh environment.
{"title":"Drilling Offshore Wells with HP WBM in Extreme HP HT Conditions","authors":"L. Affede, R. Lorefice, Larissa Pinto Vieira, M. Giubertoni, Lorenzo Buzzi, G. Carpineta","doi":"10.2523/iptc-21965-ms","DOIUrl":"https://doi.org/10.2523/iptc-21965-ms","url":null,"abstract":"\u0000 During drilling of three exploration wells challenging conditions encountered, such as temperatures up to 180°C, interbedded highly reactive shales/silts, formation pressures which required mud weights up to 2.35 sg and narrow margin between pore and fracture gradients, posed a host of technical, logistical and cost challenges to Eni activities. These conditions required an accurate drilling fluids design to maximize operational efficiency and to minimize the risks related to such an extreme environment.\u0000 Technical demands were particularly critical since the reactive shale formations had historically proved to be difficult to inhibit when drilled with Water Based Mud and might have caused swelling, tight hole, sticky wireline runs, bit-balling and accretion that could have resulted, among other issues, in low penetration rates (ROP). The formation nature coupled with ECD (Equivalent Circulation Density) constraints due to the high mud weight required to cope with high pore pressure, which also caused high mud rheology readings, were therefore the main limits to be overcome to achieve the well objectives.\u0000 A tailored drilling fluid program was thus proposed which consisted of an inhibitive HPWBM (High Performance Water Based Mud) that could be converted to an HT-HPWBM, (High Temperature-High Performances Water Based Mud) while drilling, to cross the deeper and hotter sections of the well. This fluid was specifically engineered and optimized after each well in order to contain high concentration of a combination of monovalent salts to guarantee inhibition and reduce solids loading, dedicated polyamine shale inhibitor and fluid loss additives to minimize API/HPHT filtrate and filter cake thickness with the aim to reduce shale water invasion throughout the drilling campaign, graphite to minimizes fluid invasion and fracture propagation and ROP (Rate Of Penetration) enhancer continuously injected using dedicated pump to act as anti-balling and anti-accretion additive.\u0000 The achieved results were drilling targets delivered safely, on time and with good overall fluid performances which either reduced or eliminated many of the challenges seen in offset wells, including: no barite sag, rheology stability, and stable long-term mud properties and wellbore conditions even during extended formation logs acquisitions.\u0000 This paper covers the design, execution and accomplishments of the water-based drilling fluids employed on three HP/HT wells drilled, together with all of the lessons learned captured, highlighting the evolution of these systems to reach a step-change in terms of performances in such a harsh environment.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81759873","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. Aljawder, Yusuf Engineer, Bader Alhammadi, A.Wahab Buarki
The Ahmadi formation of Bahrain field is of Middle Cretaceous age. It is predominantly a shale lying immediately below the Magwa member of the Rumaila formation and contains two limestone units in the Bahrain field, which are referred to as Aa and Ab members. Limestone Aa and Ab are present with practically uniform thickness over the entire Bahrain field area, as a blanket like deposition. The Ahmadi Reservoir in the Bahrain Field has been producing since 1933. Ahmadi consists of two main limestone units, AA and AB, separated by a 40-45 ft shale member. The AA reservoir is typically 3 to 4 feet thick, while the AB is divided into three separate units: AB1, AB2, and AB3. AB1 and AB3 are fairly clean limestone units, with a cumulative net reservoir of 12 to 14 ft. AB2 is about 4 to 5 feet thick, and characterized as a non-reservoir. The matrix permeability ranges from 1 to 2 mD. The main focus of the primary development plan was established by infill horizontal open hole lateral section, targeting the AB3 zone. However, poor matrix permeability and the irregularly spaced natural fracture network of the AB3 zone can hinder the primary development strategy and well production. Therefore, acid fracturing with 8 stages (60 ft each) in the open hole lateral section was implemented to improve well performance. A study was initiated in 2019 to improve the acid fracturing technique in the AB3 open hole lateral section (horizontal wells) by increasing the number of stages from 8 stages (60 ft each) to 18 stages (60 ft each). The wells targeted were located in areas with low reservoir quality and low fracture networks in order to induce artificial fractures, thereby improving well performance.
{"title":"A Study on Increasing the Number of Stages in the Acid Fracturing Stimulation Technique in Horizontal Wells for a Tight Fractured Carbonate Reservoir in the Bahrain Field","authors":"A. Aljawder, Yusuf Engineer, Bader Alhammadi, A.Wahab Buarki","doi":"10.2523/iptc-22586-ea","DOIUrl":"https://doi.org/10.2523/iptc-22586-ea","url":null,"abstract":"\u0000 The Ahmadi formation of Bahrain field is of Middle Cretaceous age. It is predominantly a shale lying immediately below the Magwa member of the Rumaila formation and contains two limestone units in the Bahrain field, which are referred to as Aa and Ab members. Limestone Aa and Ab are present with practically uniform thickness over the entire Bahrain field area, as a blanket like deposition.\u0000 The Ahmadi Reservoir in the Bahrain Field has been producing since 1933. Ahmadi consists of two main limestone units, AA and AB, separated by a 40-45 ft shale member. The AA reservoir is typically 3 to 4 feet thick, while the AB is divided into three separate units: AB1, AB2, and AB3. AB1 and AB3 are fairly clean limestone units, with a cumulative net reservoir of 12 to 14 ft. AB2 is about 4 to 5 feet thick, and characterized as a non-reservoir. The matrix permeability ranges from 1 to 2 mD.\u0000 The main focus of the primary development plan was established by infill horizontal open hole lateral section, targeting the AB3 zone. However, poor matrix permeability and the irregularly spaced natural fracture network of the AB3 zone can hinder the primary development strategy and well production. Therefore, acid fracturing with 8 stages (60 ft each) in the open hole lateral section was implemented to improve well performance.\u0000 A study was initiated in 2019 to improve the acid fracturing technique in the AB3 open hole lateral section (horizontal wells) by increasing the number of stages from 8 stages (60 ft each) to 18 stages (60 ft each). The wells targeted were located in areas with low reservoir quality and low fracture networks in order to induce artificial fractures, thereby improving well performance.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80863568","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}
Electrical submersible pump providers are always collaborating with client to overcome the challenges of costly ESP change out by offshore workover rigs and the conventional well intervention by offshore barges, in addition to the harsh reservoir environments due to high H2S and high temperature. Accordingly, operating companies are keen to minimize the number of ESP failures and avoid costly offshore workovers especially in high producers and when the demand of production is high. In effort to improve the ESP reliability and ensure continuous production, several recent technologies were combined to boost the run life of the overall completion. The combination of these technologies improved the run life and the reliability of the system and resulted in massive financial impact as it saves rig cost, Barge cost, wireline cost, operations cost and more importantly the deferred production. This paper will elaborate in details about the technologies utilized in this completion and how it caused considerable financial impact on both vendor and client.
{"title":"First Metal to Metal Dual Auto Switch ESP","authors":"Ali AlOlaywat","doi":"10.2523/iptc-22426-ms","DOIUrl":"https://doi.org/10.2523/iptc-22426-ms","url":null,"abstract":"\u0000 Electrical submersible pump providers are always collaborating with client to overcome the challenges of costly ESP change out by offshore workover rigs and the conventional well intervention by offshore barges, in addition to the harsh reservoir environments due to high H2S and high temperature. Accordingly, operating companies are keen to minimize the number of ESP failures and avoid costly offshore workovers especially in high producers and when the demand of production is high. In effort to improve the ESP reliability and ensure continuous production, several recent technologies were combined to boost the run life of the overall completion.\u0000 The combination of these technologies improved the run life and the reliability of the system and resulted in massive financial impact as it saves rig cost, Barge cost, wireline cost, operations cost and more importantly the deferred production.\u0000 This paper will elaborate in details about the technologies utilized in this completion and how it caused considerable financial impact on both vendor and client.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78257610","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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