Growing reliance and new technologies have significantly optimized the drilling operations; un-drillable wells become drillable now. We strive to increase drilling efficiency, whether managed pressure drilling (MPD) or conventional drilling operations. Designing an MPD operation inherits multiple challenges and requires the evaluation of numerous parameters. These include bottom hole pressure management, tripping, cementing, logging & completion operations. However, this paper only describes how the tripping processes can be optimized using effective mud cap design in very narrow window HP/HT MPD wells. Constant bottom hole MPD (CBH-MPD) is one of the extensively used variants of MPD around the globe. In CBH-MPD, Surface backpressure is the differentiating factor added to keep the bottom hole pressure (BHP) constant in static and dynamic conditions. A close-loop is necessary to attain this control on the annulus pressure with specialized equipment, including effective sealing around the drill string and choking the return flow. The sealing is only effective against the smooth surfaces; hence, one of the most significant challenges in MPD operations arises: having a constant BHP in case of pull out to the surface. If the downhole isolation valve (DIV) is deployed, the well can be shut on it. However, if a DIV is not available, the well can be balanced by designing an effective mud cap keeping the available trip margins. Planning and executing a mud cap for MPD is challenging and can be overlooked in the planning phase. Designing a mud cap is complicated as many factors need to be incorporated. This paper describes, in detail, how these challenges were identified, planned for, and overcome. Multiple parameters were analyzed in sequences for subjected wells to optimize the mud cap weight and spotting depths. These parameters include the available tripping window, bottom hole temperature, circulation pressures, mud additives, mud rheology, surge, and swab pressures. Residing time of the mud cap in the hole is also a key factor considered in the design as it may also disturb the CBH pressure. Other design considerations included rig compatibility and volume handling capacity, equipment limitations downhole and surface, availability of chemicals, and effective rollover plan. The effective mud cap design for these narrow HP/HT wells mentioned in these case studies was an arduous and challenging task. This paper also discusses the aforementioned mud cap design considerations and their effects on selecting an appropriate mud cap. Practical examples are shared from challenging case studies, elaborating the detailed design and execution aspects.
{"title":"Optimization of Mud Cap Design for Tripping Operations and its Application in Challenging HPHT MPD Wells: Case Histories from Pakistan","authors":"Shoaib Muhammad, Qasim Ashraf, U. Baig","doi":"10.4043/31668-ms","DOIUrl":"https://doi.org/10.4043/31668-ms","url":null,"abstract":"\u0000 Growing reliance and new technologies have significantly optimized the drilling operations; un-drillable wells become drillable now. We strive to increase drilling efficiency, whether managed pressure drilling (MPD) or conventional drilling operations. Designing an MPD operation inherits multiple challenges and requires the evaluation of numerous parameters. These include bottom hole pressure management, tripping, cementing, logging & completion operations. However, this paper only describes how the tripping processes can be optimized using effective mud cap design in very narrow window HP/HT MPD wells.\u0000 Constant bottom hole MPD (CBH-MPD) is one of the extensively used variants of MPD around the globe. In CBH-MPD, Surface backpressure is the differentiating factor added to keep the bottom hole pressure (BHP) constant in static and dynamic conditions. A close-loop is necessary to attain this control on the annulus pressure with specialized equipment, including effective sealing around the drill string and choking the return flow. The sealing is only effective against the smooth surfaces; hence, one of the most significant challenges in MPD operations arises: having a constant BHP in case of pull out to the surface. If the downhole isolation valve (DIV) is deployed, the well can be shut on it. However, if a DIV is not available, the well can be balanced by designing an effective mud cap keeping the available trip margins.\u0000 Planning and executing a mud cap for MPD is challenging and can be overlooked in the planning phase. Designing a mud cap is complicated as many factors need to be incorporated. This paper describes, in detail, how these challenges were identified, planned for, and overcome. Multiple parameters were analyzed in sequences for subjected wells to optimize the mud cap weight and spotting depths. These parameters include the available tripping window, bottom hole temperature, circulation pressures, mud additives, mud rheology, surge, and swab pressures. Residing time of the mud cap in the hole is also a key factor considered in the design as it may also disturb the CBH pressure. Other design considerations included rig compatibility and volume handling capacity, equipment limitations downhole and surface, availability of chemicals, and effective rollover plan. The effective mud cap design for these narrow HP/HT wells mentioned in these case studies was an arduous and challenging task.\u0000 This paper also discusses the aforementioned mud cap design considerations and their effects on selecting an appropriate mud cap. Practical examples are shared from challenging case studies, elaborating the detailed design and execution aspects.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"283 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77003605","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}
P. Batruny, M. R. Paimin, M. Allauddin, Felipe Lyra, Linda Doria, B. Castro
Subsurface uncertainty, inadequate offset wells correlation, and high investment cost are some of the biggest drilling challenges in any frontier environment or wild cat exploration wells. These challenges comes with inherent risk on people, environment, assets, and reputation. Mitigating these risks through contingency in the detailed well planning phase as well maximizing operational uptime and efficiency during the well delivery phase, greatly impact the outcome of the well. Digital tools and automation have been a cornerstone in the industry's latest tools to reduce personnel on the rig, as well as minimize downtime and inefficiency. A collaboration of experts between an Operator and Service company was formed during the well planning phase to evaluate the feasibility of an automation platform for a holistic drilling advisory platform that facilitates real time decision making based on downhole and surface data. An offset well study in the area showed that nearby wells experienced recurrence incidents of wellbore instability and downhole pore pressure uncertainty. Modeling iterations for dynamic and static drilling were simulated during pre-planning phase and optimized in real time based on actual downhole and surface data information. Real time models were compared against dynamic models such as Torque and Drag, Hole Cleaning, Pore pressure, ECD (Equivalent Circulating Density), ESD (Equivalent Static Density), and tripping speed (Swab, Surge, etc.). An automated directional drilling tool was run and compared to decisions made by the directional driller to improve the tool's decision-making process for predictive well trajectory parameters. Based on the resultant models, proactive advice was given to the rig in real-time to optimize the input parameters and reduce negative impact to well operation. For example, the practical, real-time visualization helped quickly identify a decreasing pore pressure trend and avoided resultant high overbalance while drilling the 17.5 in. × 22 in. section. The early warning alert allowed swift real time reaction sent to the rig, with mud weight subsequently decreased to 9.2 ppg, avoiding a potential risk of differential sticking stuck pipe incident due to high mud overbalance. Torque and Drag monitoring throughout the well accurately identified few instances of deviation from the trend and models, which detected an early sign of deteriorating wellbore condition which eventually led to a temporary stuck pipe event. Nevertheless, the pipe was freed, which demonstrate that the real time advisory helps in minimizing and avoiding the severe impact of the stuck pipe on the drilling operation. Automated advisory effectively delivered alerts on tight spots while drilling and casing running resulting in a faster 9-5/8 in. liner running in the deviated section. Tripping advisory mode and Real-time modelling of the swab-surge limits successfully allowed the team to avoid critical areas or swabbing events, which incr
{"title":"Operator and Service Provider Collaborate to Successfully Introduce an Automated Advisory System in a Wildcat Exploration Well Offshore Mexico","authors":"P. Batruny, M. R. Paimin, M. Allauddin, Felipe Lyra, Linda Doria, B. Castro","doi":"10.4043/31443-ms","DOIUrl":"https://doi.org/10.4043/31443-ms","url":null,"abstract":"\u0000 Subsurface uncertainty, inadequate offset wells correlation, and high investment cost are some of the biggest drilling challenges in any frontier environment or wild cat exploration wells. These challenges comes with inherent risk on people, environment, assets, and reputation. Mitigating these risks through contingency in the detailed well planning phase as well maximizing operational uptime and efficiency during the well delivery phase, greatly impact the outcome of the well. Digital tools and automation have been a cornerstone in the industry's latest tools to reduce personnel on the rig, as well as minimize downtime and inefficiency.\u0000 A collaboration of experts between an Operator and Service company was formed during the well planning phase to evaluate the feasibility of an automation platform for a holistic drilling advisory platform that facilitates real time decision making based on downhole and surface data. An offset well study in the area showed that nearby wells experienced recurrence incidents of wellbore instability and downhole pore pressure uncertainty. Modeling iterations for dynamic and static drilling were simulated during pre-planning phase and optimized in real time based on actual downhole and surface data information. Real time models were compared against dynamic models such as Torque and Drag, Hole Cleaning, Pore pressure, ECD (Equivalent Circulating Density), ESD (Equivalent Static Density), and tripping speed (Swab, Surge, etc.). An automated directional drilling tool was run and compared to decisions made by the directional driller to improve the tool's decision-making process for predictive well trajectory parameters. Based on the resultant models, proactive advice was given to the rig in real-time to optimize the input parameters and reduce negative impact to well operation.\u0000 For example, the practical, real-time visualization helped quickly identify a decreasing pore pressure trend and avoided resultant high overbalance while drilling the 17.5 in. × 22 in. section. The early warning alert allowed swift real time reaction sent to the rig, with mud weight subsequently decreased to 9.2 ppg, avoiding a potential risk of differential sticking stuck pipe incident due to high mud overbalance. Torque and Drag monitoring throughout the well accurately identified few instances of deviation from the trend and models, which detected an early sign of deteriorating wellbore condition which eventually led to a temporary stuck pipe event. Nevertheless, the pipe was freed, which demonstrate that the real time advisory helps in minimizing and avoiding the severe impact of the stuck pipe on the drilling operation. Automated advisory effectively delivered alerts on tight spots while drilling and casing running resulting in a faster 9-5/8 in. liner running in the deviated section. Tripping advisory mode and Real-time modelling of the swab-surge limits successfully allowed the team to avoid critical areas or swabbing events, which incr","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84157603","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}
Offshore wind farms are venturing into deeper water, where wind is steadier and stronger, to tap on more wind energy. The installation of wind turbines in deeper waters requires the use of a floating wind turbine. Designing the floating platforms is challenging as dynamic effects waves, wind, and currents, have to be considered. Hydrodynamic behaviours can only be modelled accurately in time domain analysis, which requires an immense computational effort, when several load cases are taken into consideration. A more efficient approach is to first conduct stability analysis to identify the modal frequencies, and subsequently carry out time domain analysis using those modal frequencies. This paper describes a static study and time domain analysis on an innovative offshore spar turbine with hulls. Ansys Aqwa, a finite-element software, is used to study a model proposed by Mitsubishi Heavy Industries. The key objective is to explore a more cost-effective offshore platform by investigating the relationship between the geometry of hulls and the responses of the platform.
{"title":"A Modelling Study of Hamakaze Fowt","authors":"Wei Ywin Teo, P. P. Ong","doi":"10.4043/31468-ms","DOIUrl":"https://doi.org/10.4043/31468-ms","url":null,"abstract":"\u0000 Offshore wind farms are venturing into deeper water, where wind is steadier and stronger, to tap on more wind energy. The installation of wind turbines in deeper waters requires the use of a floating wind turbine. Designing the floating platforms is challenging as dynamic effects waves, wind, and currents, have to be considered. Hydrodynamic behaviours can only be modelled accurately in time domain analysis, which requires an immense computational effort, when several load cases are taken into consideration. A more efficient approach is to first conduct stability analysis to identify the modal frequencies, and subsequently carry out time domain analysis using those modal frequencies.\u0000 This paper describes a static study and time domain analysis on an innovative offshore spar turbine with hulls. Ansys Aqwa, a finite-element software, is used to study a model proposed by Mitsubishi Heavy Industries. The key objective is to explore a more cost-effective offshore platform by investigating the relationship between the geometry of hulls and the responses of the platform.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78246138","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}
Feng Deng, Shiwen Chen, Guanhong Chen, Meng-ying Wang
Quantitative information regarding multi-phase flow of oil, gas and water in wells or pipelines are very important in guiding the artificial lifting parameters optimization and tool selection. At present, there is no reliable technology available which can accurately measure split flow of multi-phase fluids without separating oil, gas and water. So far, the multi-phase flow measurement technique commonly adopted globally is to carry out by phase separation after produced fluid entering the gathering station through the pipelines, where the content of each component is measured separately. The indirect measurement methods are usually with low-efficiency, high-cost and delay-delivery, and hard to reflect the real instantaneous fluid producing properties at wellheads or pipelines. Therefore, it is urgent to seek for accurate and reliable multi-phase flow detection devices and methods that can meet the monitoring demands for oil and gas resources. This paper proposed a nuclear magnetic resonance (NMR) device and analytical methods for detecting multi-phase fluid. At the same time, it puts forward the intelligent decision-making and optimization technology based on measurement, cloud computing and automatic control. As a green, efficient and accurate method for oil and gas detection, the NMR can realize online measurement for each component of multi-phase flow. Then based on the internet and large data analysis technology to achieve artificial lifting parameters optimization, while based on automatic control technology to achieve artificial lifting equipment negative feedback control. This progress helps to apply the NMR technique in petroleum industry to achieve green, efficient, real-time and low-cost multi-phase flow measurement. Combined with large data, Internet of Things (IOT) and automatic control technology to achieve intelligent artificial lifting technology and system.
{"title":"Intelligent Decision Making and Optimization of Artificial Lifting Based on MR Multi-Phase Flow Detection","authors":"Feng Deng, Shiwen Chen, Guanhong Chen, Meng-ying Wang","doi":"10.4043/31349-ms","DOIUrl":"https://doi.org/10.4043/31349-ms","url":null,"abstract":"\u0000 Quantitative information regarding multi-phase flow of oil, gas and water in wells or pipelines are very important in guiding the artificial lifting parameters optimization and tool selection. At present, there is no reliable technology available which can accurately measure split flow of multi-phase fluids without separating oil, gas and water. So far, the multi-phase flow measurement technique commonly adopted globally is to carry out by phase separation after produced fluid entering the gathering station through the pipelines, where the content of each component is measured separately. The indirect measurement methods are usually with low-efficiency, high-cost and delay-delivery, and hard to reflect the real instantaneous fluid producing properties at wellheads or pipelines. Therefore, it is urgent to seek for accurate and reliable multi-phase flow detection devices and methods that can meet the monitoring demands for oil and gas resources.\u0000 This paper proposed a nuclear magnetic resonance (NMR) device and analytical methods for detecting multi-phase fluid. At the same time, it puts forward the intelligent decision-making and optimization technology based on measurement, cloud computing and automatic control. As a green, efficient and accurate method for oil and gas detection, the NMR can realize online measurement for each component of multi-phase flow. Then based on the internet and large data analysis technology to achieve artificial lifting parameters optimization, while based on automatic control technology to achieve artificial lifting equipment negative feedback control.\u0000 This progress helps to apply the NMR technique in petroleum industry to achieve green, efficient, real-time and low-cost multi-phase flow measurement. Combined with large data, Internet of Things (IOT) and automatic control technology to achieve intelligent artificial lifting technology and system.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88557969","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}
Hamimah Abedul Talik, Hayati Hussien, M. A. A. M Wazir, S. Azman
Fully-rated design is often opts when the well's pressure is within #1500 range since the pipeline cost is perceived cheaper during the early design stage due to inadequate design detailing. Initially, a 16-inch carbon steel pipeline was designed based on a constant maximum closed-in tubing head pressure (CITHP) of 219 barg with 90 °C design temperature based on flowing tubing head temperature (FTHT) plus ~10 °C margins. This arrived with a pipeline wall thickness (WT) of 25.4 mm for the riser and 20.62 mm for the subsea pipeline. The pipeline also required three (3) buckle triggers to manage lateral buckling. To make matter worst, the specified minimum design temperature was -41 °C. This would lead to unnecessary project cost especially when this maximum CITHP would only happen during the first month of production and is expected to deplete as low as 58 barg towards the end of 15-years production life while the FTHT of 77.1 °C that led to 90 °C maximum design temperature would only be seen at the topside header during a pipeline linepacking scenario due to failure of shutdown valve which led to production's blocked discharge. This paper will relate a cost reduction exercise by performing a detailed flow assurance analysis to optimize the design parameters to avoid the requirement of buckle triggers and excessive linepipe testing requirements for minimum temperature that could not be guaranteed by the manufacturer. Detailed hydraulic analysis was conducted based on final pipeline data to develop pressure and temperature profile. To determine the pipeline maximum design temperature, the worst-case scenario i.e., a combination of maximum CITHP and associated temperature during line packing, was considered as the governing case. However, transient analysis was performed with the point of measurement taken at the downstream choke valve, which normally has a reduced temperature as compared with FTHT. Different production wells’ start-up method was proposed to analyze various possible steps to avoid very low temperature that derived the minimum design temperature. For both maximum and minimum temperature, the simulation models were refined with detailed dimension of topside and pipeline system incorporating each important point to obtain more accurate pipeline temperature at the inlet and other important locations. Inner wall temperature was used instead of fluid temperature. Pipeline maximum design temperature was reduced from 90 °C to 81 °C, eliminating the requirement of buckle triggers, while minimum design temperature was increased from -41 °C to -15 °C for the riser and 0 °C for the subsea pipeline. Additionally, the riser's wall thickness was optimized by taking advantage of the depleting CITHP to reduce the thickness from 25.4 mm to 22.23 mm to suit magnetic field leakage (MFL) intelligent pigging (IP) inspection tool currently available in the market. The estimated cost reduction from the exercise was at least around 5.4 million ringgits.
当井的压力在1500范围内时，通常选择全额定设计，因为在早期设计阶段，由于设计细节不足，管道成本被认为更低。最初，设计了一条16英寸的碳钢管道，最大关井管头压力(CITHP)恒定为219巴，设计温度为90°C，基于流动管头温度(FTHT)加上~10°C的裕度。最终，立管的管壁厚度(WT)为25.4 mm，海底管道的管壁厚度为20.62 mm。管道还需要三(3)个扣扣触发器来控制侧向屈曲。更糟糕的是，规定的最低设计温度为-41°C。这将导致不必要的项目成本，特别是当最高温度仅在生产的第一个月发生时，并且预计在15年的生产寿命结束时消耗低至58巴，而77.1°C的FTHT导致90°C的最高设计温度仅在管道包装场景中出现在顶部集箱中，这是由于关闭阀失效导致生产堵塞排放。本文将通过执行详细的流动保证分析来优化设计参数，从而降低成本，以避免对扣环触发器的要求，以及对制造商无法保证的最低温度的过多管道测试要求。根据最终的管道数据进行了详细的水力分析，以确定压力和温度分布。为了确定管道的最高设计温度，考虑了最坏情况，即管道填料过程中最大潜热和相关温度的组合。然而，瞬态分析是在下游节流阀处进行的，与FTHT相比，下游节流阀的温度通常较低。提出了不同生产井的启动方法，分析了避免过低温度的各种可能步骤。对于最高温度和最低温度，对模拟模型进行了细化，将上层甲板和管道系统的详细尺寸纳入每个重要点，以获得更准确的入口和其他重要位置的管道温度。用内壁温度代替流体温度。管道最高设计温度从90°C降低到81°C，消除了扣环触发器的要求，而立管的最低设计温度从-41°C提高到-15°C，海底管道的最低设计温度从0°C提高到0°C。此外，利用损耗式CITHP对隔水管的壁厚进行了优化，将隔水管的壁厚从25.4 mm减少到22.23 mm，以适应目前市场上可用的漏磁(MFL)智能清管(IP)检测工具。据估计，这次演习的成本至少减少了540万令吉左右。最初选择的16英寸管道，WT为25.4 mm，也不适合电阻焊(ERW)和纵向埋弧焊(LSAW)制造方法。此外，使用MFL检测工具在线检测管道的现有信息仅适用于24.64 mm WT。
{"title":"Pipeline Project Cost Optimization by Refining the Design Parameter Based on the Associated Concerns","authors":"Hamimah Abedul Talik, Hayati Hussien, M. A. A. M Wazir, S. Azman","doi":"10.4043/31635-ms","DOIUrl":"https://doi.org/10.4043/31635-ms","url":null,"abstract":"\u0000 Fully-rated design is often opts when the well's pressure is within #1500 range since the pipeline cost is perceived cheaper during the early design stage due to inadequate design detailing. Initially, a 16-inch carbon steel pipeline was designed based on a constant maximum closed-in tubing head pressure (CITHP) of 219 barg with 90 °C design temperature based on flowing tubing head temperature (FTHT) plus ~10 °C margins. This arrived with a pipeline wall thickness (WT) of 25.4 mm for the riser and 20.62 mm for the subsea pipeline. The pipeline also required three (3) buckle triggers to manage lateral buckling. To make matter worst, the specified minimum design temperature was -41 °C. This would lead to unnecessary project cost especially when this maximum CITHP would only happen during the first month of production and is expected to deplete as low as 58 barg towards the end of 15-years production life while the FTHT of 77.1 °C that led to 90 °C maximum design temperature would only be seen at the topside header during a pipeline linepacking scenario due to failure of shutdown valve which led to production's blocked discharge. This paper will relate a cost reduction exercise by performing a detailed flow assurance analysis to optimize the design parameters to avoid the requirement of buckle triggers and excessive linepipe testing requirements for minimum temperature that could not be guaranteed by the manufacturer.\u0000 Detailed hydraulic analysis was conducted based on final pipeline data to develop pressure and temperature profile. To determine the pipeline maximum design temperature, the worst-case scenario i.e., a combination of maximum CITHP and associated temperature during line packing, was considered as the governing case. However, transient analysis was performed with the point of measurement taken at the downstream choke valve, which normally has a reduced temperature as compared with FTHT. Different production wells’ start-up method was proposed to analyze various possible steps to avoid very low temperature that derived the minimum design temperature. For both maximum and minimum temperature, the simulation models were refined with detailed dimension of topside and pipeline system incorporating each important point to obtain more accurate pipeline temperature at the inlet and other important locations. Inner wall temperature was used instead of fluid temperature.\u0000 Pipeline maximum design temperature was reduced from 90 °C to 81 °C, eliminating the requirement of buckle triggers, while minimum design temperature was increased from -41 °C to -15 °C for the riser and 0 °C for the subsea pipeline. Additionally, the riser's wall thickness was optimized by taking advantage of the depleting CITHP to reduce the thickness from 25.4 mm to 22.23 mm to suit magnetic field leakage (MFL) intelligent pigging (IP) inspection tool currently available in the market. The estimated cost reduction from the exercise was at least around 5.4 million ringgits.\u0000","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86357730","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 total crude oil resources are approximately 9-11 trillion barrels around the world and the steam based thermal recovery processes are still the most effective methods to enhance heavy oil recovery. Due to the high oil viscosity, high fluid temperature and high fluid volume changes with time, the choice of suitable artificial lift (AL) system is one of the most important techniques in optimizing production from thermally developed heavy oil wells. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift system in thermally developed heavy oil reservoirs, there remains differing assessments of the best approach, AL type for various kinds of thermal recovery methods. A comprehensive review of artificial lift systems application with specific focus on thermally developed heavy oil reservoirs across the world for offshore oilfields is conducted. The review focuses on the special designed artificial lift system with functions of both steam injection and oil production for offshore oilfield. At the same time, the purpose of this work is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed for thermally developed heavy oil reservoirs in the future.
{"title":"Artificial Lift System Applications for Thermally Developed Offshore Heavy Oil Reservoirs","authors":"Hua Zhang, Ping-li Liu, Qiuxia Wang, Jian-hua Bai, Wei Zhang, Hongwen Zhang, Xiaodong Han","doi":"10.4043/31549-ms","DOIUrl":"https://doi.org/10.4043/31549-ms","url":null,"abstract":"\u0000 The total crude oil resources are approximately 9-11 trillion barrels around the world and the steam based thermal recovery processes are still the most effective methods to enhance heavy oil recovery. Due to the high oil viscosity, high fluid temperature and high fluid volume changes with time, the choice of suitable artificial lift (AL) system is one of the most important techniques in optimizing production from thermally developed heavy oil wells.\u0000 Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift system in thermally developed heavy oil reservoirs, there remains differing assessments of the best approach, AL type for various kinds of thermal recovery methods. A comprehensive review of artificial lift systems application with specific focus on thermally developed heavy oil reservoirs across the world for offshore oilfields is conducted. The review focuses on the special designed artificial lift system with functions of both steam injection and oil production for offshore oilfield. At the same time, the purpose of this work is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed for thermally developed heavy oil reservoirs in the future.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84482017","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}
Intiran Raman, Yulian Wardhana, Kasim B. Selamat, B. Shepheard, M. N. Ghazali, J. Blacklock, Hattaya Tulathammakit, Zengzhen Liu, Gopalan Bathmanaaban
Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system. An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories. This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.
{"title":"Innovative Rigless-Deployed Electrical Submersible Pump ESP System for Installation at Floating Deep-Water Production Platform","authors":"Intiran Raman, Yulian Wardhana, Kasim B. Selamat, B. Shepheard, M. N. Ghazali, J. Blacklock, Hattaya Tulathammakit, Zengzhen Liu, Gopalan Bathmanaaban","doi":"10.4043/31479-ms","DOIUrl":"https://doi.org/10.4043/31479-ms","url":null,"abstract":"\u0000 Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system.\u0000 An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories.\u0000 This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87472437","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. L. Ismail, M. F. Ishak, M. I. Idris, Hazlan Abdul Hakim, M. F. Othman, Kayathiri Chandran, A. H. Alias, M. Rozlan, M. H. M Ghazali
When the pandemic COVID-19 erupted and spreaded throughout the world, numerous rules and regulations were implemented to ensure the safety of everyone. The outcome of Covid-19 resulted in a global shutdown, where cases continued to grow rapidly that directly affected the normal processes in all business sectors. While the future is still uncertain, business plan must keep on progressing by managing all the obstacles to ensure the business goal is delivered efficaciously while keeping the impact as low as possible. In the early stage of the outbreak, there was limited knowledge and experience to manage a drilling campaign virtually, to ensure all plans are smooth despite all the restrictions to avoid additional cost and schedule impact to the company. Since the outbreak was quite abrupt, the main challenge faced by the team was to ensure a continuous operation like any other year before but with additional enforcement of stringent COVID-19 SOP and to come up with new modus operandi with stringent SOP at every location. During this pandemic, the operation is exposed to the risk of being on standby mode due to equipment unavailability, unreadiness of manpower or delay in vessel movement. Knowing that drilling operation is so dynamic, that a slight change to the drilling sequence could lead to operation shutdown if the required services are not readily onboard. This uncomplimentary impact is due to the new rules or regulations implemented on the manpower and equipment movement to reduce risk of Covid-19 infection. Therefore, a thorough planning is crucial to ensure the success of operation, in fact a few fallback plans must be in placed to minimize the cost and schedule exposure. This paper will address the challenges in managing equipment and manpower throughout the operation for BX-Project together with the solutions to ensure the governance, rules and regulations of Covid-19 are being followed. The approaches taken during this campaign is used as a baseline to run a drilling operation during Covid-19 pandemic in the upcoming year. Lessons learnt captured from this campaign can be replicated by other projects and finding the more efficient ways to implement the best practices. This pandemic has challenged our perseverance to deliver the project objectives while maintaining the dedication, health, focus as well as creativity to overcome unfamiliar circumstances.
{"title":"An Era to Remember: Managing Offshore Drilling Campaign During World Pandemic Covid-19 Crisis","authors":"A. L. Ismail, M. F. Ishak, M. I. Idris, Hazlan Abdul Hakim, M. F. Othman, Kayathiri Chandran, A. H. Alias, M. Rozlan, M. H. M Ghazali","doi":"10.4043/31547-ms","DOIUrl":"https://doi.org/10.4043/31547-ms","url":null,"abstract":"\u0000 When the pandemic COVID-19 erupted and spreaded throughout the world, numerous rules and regulations were implemented to ensure the safety of everyone. The outcome of Covid-19 resulted in a global shutdown, where cases continued to grow rapidly that directly affected the normal processes in all business sectors. While the future is still uncertain, business plan must keep on progressing by managing all the obstacles to ensure the business goal is delivered efficaciously while keeping the impact as low as possible. In the early stage of the outbreak, there was limited knowledge and experience to manage a drilling campaign virtually, to ensure all plans are smooth despite all the restrictions to avoid additional cost and schedule impact to the company.\u0000 Since the outbreak was quite abrupt, the main challenge faced by the team was to ensure a continuous operation like any other year before but with additional enforcement of stringent COVID-19 SOP and to come up with new modus operandi with stringent SOP at every location. During this pandemic, the operation is exposed to the risk of being on standby mode due to equipment unavailability, unreadiness of manpower or delay in vessel movement. Knowing that drilling operation is so dynamic, that a slight change to the drilling sequence could lead to operation shutdown if the required services are not readily onboard. This uncomplimentary impact is due to the new rules or regulations implemented on the manpower and equipment movement to reduce risk of Covid-19 infection. Therefore, a thorough planning is crucial to ensure the success of operation, in fact a few fallback plans must be in placed to minimize the cost and schedule exposure.\u0000 This paper will address the challenges in managing equipment and manpower throughout the operation for BX-Project together with the solutions to ensure the governance, rules and regulations of Covid-19 are being followed. The approaches taken during this campaign is used as a baseline to run a drilling operation during Covid-19 pandemic in the upcoming year. Lessons learnt captured from this campaign can be replicated by other projects and finding the more efficient ways to implement the best practices. This pandemic has challenged our perseverance to deliver the project objectives while maintaining the dedication, health, focus as well as creativity to overcome unfamiliar circumstances.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79502221","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}
Kuqa foreland basin in Tarim Oilfield is the largest ultra-high pressure gas fields in the world, with buried depth of 6000-10000 m and reservoir pressure of 115-14 MPa. Complex geological conditions, extreme working conditions and harsh corrosion environment bring great challenges to the integrity of high-pressure gas wells. This paper introduces the safety control technology for the ultra-high pressure gas wells, which ensures the safe production. For economic development ultra-high pressure gas field, it is essential to control the safety of high annular pressure. Field investigation of abnormal pressure indicates the previous design method and pressure control measures of two-stage barrier decreasing step by step in ultra-high pressure gas wells are difficult to meet the requirements of fine safety control. Therefore, the annular pressure safety control technology with the core of "two-stage well barrier equal strength design, annular pressure dynamic window control and pressure grading control" is established to realize the fine control of ultra-high pressure gas wells. Firstly,in the stage of ultra-high pressure gas well wellbore design, based on the equal strength design method, 140 MPa metal seal easily replaceable casing head and small coupling production casing are developed, which are integrated with the equal strength tubing string and Christmas tree to realize the "double insurance" of wellbore pressure. Even if the primary barrier fails, the secondary barrier can still prevent the leakage of high pressure gas.Secondly, based on international standards such as API RP 90-2 and ISO16530, the calculation method and control chart of annular allowable pressure dynamic window were established before ultra-high pressure gas wells were put into production. To improve the scientific foundation of annular pressure control, the damaged or failure mode of well barrier was taken into account to guide the annular pressure management. Finally, a management method was established for the production of ultra-high pressure gas wells, including risk assessment process and hierarchical management, and the hierarchical response measures are formulated to ensure the safety and stability of oil and gas wells, which can avoid the high risk and high investment brought by work over operations. Based on the safety control technology of ultra-high pressure annulus pressure in Tarim Oilfield, the proportion of oil casing annulus pressure in new wells is reduced from 40% to 0% within one year, and the overall annulus abnormal pressure well is reduced from 29.4% to 19.7%, which ensures the effective development and safe production of ultra-high pressure gas fields in Kuqa foreland basin.
塔里木油田库车前陆盆地是世界上最大的超高压气田，埋深6000 ~ 10000 m，储层压力115 ~ 14 MPa。复杂的地质条件、极端的工作条件和恶劣的腐蚀环境给高压气井的完整性带来了极大的挑战。介绍了超高压气井的安全控制技术，保证了超高压气井的安全生产。超高压气田的经济发展，对高环空压力的安全控制至关重要。现场异常压力调查表明，超高压气井原有的两级屏障逐级递减的设计方法和压控措施难以满足精细安全控制的要求。为此，建立了以“两级井隔等强度设计、环空压力动态窗口控制和压力分级控制”为核心的环空压力安全控制技术，实现超高压气井的精细控制。首先，在超高压气井井筒设计阶段，基于等强度设计方法，研制了140 MPa金属密封易更换套管头和小型联轴器生产套管，并与等强度管柱和采油树相结合，实现井筒压力的“双重保险”。即使一次屏障失效，二次屏障仍然可以防止高压气体的泄漏。其次，根据API RP 90-2、ISO16530等国际标准，建立了超高压气井投产前环空允许压力动态窗口的计算方法和控制图;为了提高环空压力控制的科学依据，考虑井眼屏障的损坏或失效模式，指导环空压力管理。最后，建立了超高压气井生产的管理方法，包括风险评估流程和分级管理，并制定了分级应对措施，确保油气井的安全稳定，避免了超高压作业带来的高风险和高投资。基于塔里木油田超高压环空压力安全控制技术，在一年内将新井油套环空压力占比从40%降至0%，环空异常井总压力从29.4%降至19.7%，保证了库车前陆盆地超高压气田的有效开发和安全生产。
{"title":"Safety Control Technology of Ultra-High Pressure Gas Wells with Annular Pressure: Case Study of Tarim Oilfield","authors":"Lihu Cao, Jinsheng Sun, Bo Zhang","doi":"10.4043/31458-ms","DOIUrl":"https://doi.org/10.4043/31458-ms","url":null,"abstract":"\u0000 Kuqa foreland basin in Tarim Oilfield is the largest ultra-high pressure gas fields in the world, with buried depth of 6000-10000 m and reservoir pressure of 115-14 MPa. Complex geological conditions, extreme working conditions and harsh corrosion environment bring great challenges to the integrity of high-pressure gas wells. This paper introduces the safety control technology for the ultra-high pressure gas wells, which ensures the safe production. For economic development ultra-high pressure gas field, it is essential to control the safety of high annular pressure. Field investigation of abnormal pressure indicates the previous design method and pressure control measures of two-stage barrier decreasing step by step in ultra-high pressure gas wells are difficult to meet the requirements of fine safety control. Therefore, the annular pressure safety control technology with the core of \"two-stage well barrier equal strength design, annular pressure dynamic window control and pressure grading control\" is established to realize the fine control of ultra-high pressure gas wells. Firstly,in the stage of ultra-high pressure gas well wellbore design, based on the equal strength design method, 140 MPa metal seal easily replaceable casing head and small coupling production casing are developed, which are integrated with the equal strength tubing string and Christmas tree to realize the \"double insurance\" of wellbore pressure. Even if the primary barrier fails, the secondary barrier can still prevent the leakage of high pressure gas.Secondly, based on international standards such as API RP 90-2 and ISO16530, the calculation method and control chart of annular allowable pressure dynamic window were established before ultra-high pressure gas wells were put into production. To improve the scientific foundation of annular pressure control, the damaged or failure mode of well barrier was taken into account to guide the annular pressure management. Finally, a management method was established for the production of ultra-high pressure gas wells, including risk assessment process and hierarchical management, and the hierarchical response measures are formulated to ensure the safety and stability of oil and gas wells, which can avoid the high risk and high investment brought by work over operations. Based on the safety control technology of ultra-high pressure annulus pressure in Tarim Oilfield, the proportion of oil casing annulus pressure in new wells is reduced from 40% to 0% within one year, and the overall annulus abnormal pressure well is reduced from 29.4% to 19.7%, which ensures the effective development and safe production of ultra-high pressure gas fields in Kuqa foreland basin.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83340930","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}
Oil recovery in modern fields is challenging due to the reservoir complexity and heterogeneity. The need is to improve the efficacy of additives used in oil mobilization under higher pressure, temperature, and salinity conditions. The nanoparticles provide improved and sustainable solutions for improving oil recovery. Silicon carbide nanoparticle exhibits negligible agglomeration and impart higher thermal stability to the displacing fluid for oil mobilization at higher salinity. The SIC nanoparticles are being used in EOR Applications for the first time owing to their adsorption reduction potential and thermal stability at elevated temperatures. The study estimates this nanoparticle's enhanced oil recovery potential using electrical conductivity, surface tension reduction, and crude oil mobilization. The concentration of SDS was varied from zero-4000 ppm and that of SIC from 100 ppm to 300 ppm. The solution's surface tension and critical micelle concentration (CMC) conductivity were measured at elevated temperatures (30°C, 50°C, and 70°C) with and without nanoparticles. The adsorption studies were performed for 72 hours with 10 wt% of sand added to the solution. The loss of surfactant onto the sand was calculated by studying the variation electrical conductivity before and after adsorption. Surface tension reduces from 70.15 to 28.5 mN/m with increasing SDS and nanoparticles concentrations in the solution. The CMC values of the SDS+SIC solution were lower than that of the independent surfactant system, even at higher temperatures of 70°C. SDS adsorption increased from 0.80 to 6.27 mg/g as the surfactant concentration increased up to 4000 ppm. It was reduced by about 10% and 20% for 100 ppm and 200 ppm of the nanoparticles. However, at 300 ppm, the agglomeration of nanoparticles renders them ineffective in controlling adsorption.
{"title":"Effect of Silicon Carbide on the Surface Tension and Adsorption of SDS on the Sandstone Formation","authors":"Anurag Pandey, Vishnu Roy, H. Kesarwani, Govind Mittal, Shivanjali Sharma, Anika Saxena","doi":"10.4043/31439-ms","DOIUrl":"https://doi.org/10.4043/31439-ms","url":null,"abstract":"\u0000 Oil recovery in modern fields is challenging due to the reservoir complexity and heterogeneity. The need is to improve the efficacy of additives used in oil mobilization under higher pressure, temperature, and salinity conditions. The nanoparticles provide improved and sustainable solutions for improving oil recovery. Silicon carbide nanoparticle exhibits negligible agglomeration and impart higher thermal stability to the displacing fluid for oil mobilization at higher salinity. The SIC nanoparticles are being used in EOR Applications for the first time owing to their adsorption reduction potential and thermal stability at elevated temperatures. The study estimates this nanoparticle's enhanced oil recovery potential using electrical conductivity, surface tension reduction, and crude oil mobilization. The concentration of SDS was varied from zero-4000 ppm and that of SIC from 100 ppm to 300 ppm. The solution's surface tension and critical micelle concentration (CMC) conductivity were measured at elevated temperatures (30°C, 50°C, and 70°C) with and without nanoparticles. The adsorption studies were performed for 72 hours with 10 wt% of sand added to the solution. The loss of surfactant onto the sand was calculated by studying the variation electrical conductivity before and after adsorption. Surface tension reduces from 70.15 to 28.5 mN/m with increasing SDS and nanoparticles concentrations in the solution. The CMC values of the SDS+SIC solution were lower than that of the independent surfactant system, even at higher temperatures of 70°C. SDS adsorption increased from 0.80 to 6.27 mg/g as the surfactant concentration increased up to 4000 ppm. It was reduced by about 10% and 20% for 100 ppm and 200 ppm of the nanoparticles. However, at 300 ppm, the agglomeration of nanoparticles renders them ineffective in controlling adsorption.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88462281","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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