Somkiat Katanyoowongchareon, A. Danthainum, T. Chattratichart, J. Sriparagul, A. Kongchang, Napath Ruamchomrat, Suratchata Suankem
Offshore platforms in Gulf of Thailand have been aging and reaching their end of service life. To safely operate in aging platforms beyond their original intended service life, all possible operation risks need to be assessed through design review, condition assessment, inspection strategy and technique for the platform life extension stage. Qualitative or Semi-quantitative risk assessment was generally utilized by adopting scoring rule based on the condition assessment through inspection data/anomalies. A general subsea inspection campaign requested a costly additional air diving campaign for ACFM for joints with low fatigue life without a consideration of past inspection results. In practice, the routine inspection should be arranged in such a way that the operation risk meets the as-low-as practically possible (ALARP) criteria and yet minimize the cost, time and resources required for inspection. A quantitative risk assessment (QRA) and structural reliability analysis (SRA) are applied within PTTEP to evaluate and predict platform's risk development through time dependent probability of system failure. Inspection strategy including interval (when), locations (where), and suitable equipment and technique (how) are quantitatively incorporated into a mathematical model. The system probability of failure incorporating the system degradation is evaluated and inspection is triggered when the risk exceeds the allowable threshold. A complementary statistical decision model to evaluate the suitable inspection interval considered cost of failure, loss of production, and inspection is also employed. Results of quantitative method shows that the inspection interval can be prolonged, particularly, for well-designed and well-maintained platforms with reducing demand of additional air diving campaign. For most platform with relatively low to moderate consequences of failure, the inspection interval can be extended up until 10 years with routine general visual inspection (GVI), Flooded Member Detection (FMD) operated by remotely operated vehicle (ROV), provided that no significant anomalies are reported during the entire platform life cycle. In Summary, the approaches minimize the demand for additional air diving operation leading a reduction in additional cost, operational risk, and carbon footprint at least 250MT. The offshore structural integrity management and life extension programme for platform after service life by QRA is considered as new leveraged paradigm and delivers the cutting-edge integrity management programme leading to the most optimized operational cost with philosophy of safety and sustainability.
{"title":"Structural Reliability Analysis and Quantitative Risk Assessment for Optimizing Cost of Offshore Structural Integrity Management and Life Extension Programme without Air Diving Operation","authors":"Somkiat Katanyoowongchareon, A. Danthainum, T. Chattratichart, J. Sriparagul, A. Kongchang, Napath Ruamchomrat, Suratchata Suankem","doi":"10.2523/iptc-22856-ms","DOIUrl":"https://doi.org/10.2523/iptc-22856-ms","url":null,"abstract":"\u0000 Offshore platforms in Gulf of Thailand have been aging and reaching their end of service life. To safely operate in aging platforms beyond their original intended service life, all possible operation risks need to be assessed through design review, condition assessment, inspection strategy and technique for the platform life extension stage. Qualitative or Semi-quantitative risk assessment was generally utilized by adopting scoring rule based on the condition assessment through inspection data/anomalies. A general subsea inspection campaign requested a costly additional air diving campaign for ACFM for joints with low fatigue life without a consideration of past inspection results. In practice, the routine inspection should be arranged in such a way that the operation risk meets the as-low-as practically possible (ALARP) criteria and yet minimize the cost, time and resources required for inspection. A quantitative risk assessment (QRA) and structural reliability analysis (SRA) are applied within PTTEP to evaluate and predict platform's risk development through time dependent probability of system failure. Inspection strategy including interval (when), locations (where), and suitable equipment and technique (how) are quantitatively incorporated into a mathematical model. The system probability of failure incorporating the system degradation is evaluated and inspection is triggered when the risk exceeds the allowable threshold. A complementary statistical decision model to evaluate the suitable inspection interval considered cost of failure, loss of production, and inspection is also employed. Results of quantitative method shows that the inspection interval can be prolonged, particularly, for well-designed and well-maintained platforms with reducing demand of additional air diving campaign. For most platform with relatively low to moderate consequences of failure, the inspection interval can be extended up until 10 years with routine general visual inspection (GVI), Flooded Member Detection (FMD) operated by remotely operated vehicle (ROV), provided that no significant anomalies are reported during the entire platform life cycle.\u0000 In Summary, the approaches minimize the demand for additional air diving operation leading a reduction in additional cost, operational risk, and carbon footprint at least 250MT. The offshore structural integrity management and life extension programme for platform after service life by QRA is considered as new leveraged paradigm and delivers the cutting-edge integrity management programme leading to the most optimized operational cost with philosophy of safety and sustainability.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116044408","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}
Ashikin Kamaludin, M. S. M Ariffin, Lau Chee Hen, Avinash Kishore Kumar, Aizat Noh
Completing primary cementing operations under the rig floor (also known as offline cementing) instead of conventional cementing is an emerging approach that continues to gain industry interest. This is because of the opportunity this method presents for reducing operational flat time and optimizing rig use, resulting in significant cost savings. It is essential to relate the concept of offline cementing with regards to hydrocarbons (HCs) presence in the formation. Offline cementing is a straightforward method when there are no HCs present in the wellbore and when the pore pressure is at hydrostatic. A single barrier in the form of overbalance mud weight is acceptable for this condition. However, when HCs are present and/or over-pressured formation, a dual barrier (mechanical and Kill Weight Mud, KWM) is necessary to help prevent uncontrolled influx from the borehole to the external environment. During the Malaysian operation discussed here, this barrier requirement was also essential to local regulatory procedures and guidelines for upstream activities as well as the operating company's technical standard for well barriers and integrity. Thus, two well barriers were required during all well activities and operations. A dual barrier offline cementing (DBOC) system with special application of Treating Iron Works Valves (TIW Valves) and a Subsea Release (SSR) plug set was constructed to enable offline cementing within the HC section. This concept not only allowed cementing job to be executed, but at the same time allows other offline drilling activities, such as surface equipment rig-up, pressure testing lines, pre-job circulation, and cementing operations to be done while at the same time maintaining the two-barrier requirement while the blowout preventer (BOP) is removed. A new set of challenges were encountered while completing offline cementing across a HC section. Because the environment for placing a competent cement slurry was not optimal, the quality of the wellbore seal could have potentially been affected. Thus, a tailored job procedure coupled with continuous engagement between the operating company, service partners and rig owner (through joint risk-assessment sessions) established alignment and suitability of individual operations. The cement slurry design was carefully tailored, and a detailed computer aided simulation was performed to help ensure cementing operations could be accomplished without compromising operational objectives. As a result, the DBOC concept was successfully implemented for the first time in Malaysia across three highly deviated development wells, thus streamlining cementing activities. A recent collaboration in a major Malaysian National Oil Company (NOC) is highlighted, discussing the materialization of unconventional offline cementing objectives across a HC section in a challenging wellbore environment while minimizing rig time and maintaining safety standards. Various challenges encountered are discussed
在钻井平台下完成一次固井作业(也称为离线固井)，而不是传统的固井，是一种新兴的方法，不断引起行业的兴趣。这是因为该方法提供了减少作业时间和优化钻机使用的机会，从而大大节省了成本。将离线固井的概念与地层中存在的碳氢化合物(hc)联系起来是至关重要的。当井筒中不存在hc且孔隙压力处于静水状态时，离线固井是一种简单的方法。在这种情况下，以过平衡泥浆比重形式的单一屏障是可以接受的。然而，当hc存在和/或地层超压时，需要双重屏障(机械和压井泥浆，KWM)来帮助防止从井眼到外部环境的不受控制的流入。在马来西亚的作业中，这种屏障要求对于当地的监管程序和上游活动指导方针以及运营公司的井屏障和完整性技术标准也是至关重要的。因此，在所有的油井活动和作业过程中，都需要两个井眼屏障。为了实现HC段的离线固井，设计了双屏障离线固井(DBOC)系统，该系统采用了特殊的TIW阀门(treatment Iron Works Valves)和海底释放(SSR)桥塞组。该概念不仅可以执行固井作业，还可以同时进行其他离线钻井活动，例如地面设备的安装、压力测试线、作业前循环和固井作业，同时在拆除防喷器(BOP)时保持双屏障要求。在完成HC段的离线固井时，遇到了一系列新的挑战。由于注入称职水泥浆的环境不是最佳的，因此可能会影响井筒密封的质量。因此，在作业公司、服务合作伙伴和钻机所有者之间(通过联合风险评估会议)的持续参与下，量身定制的作业程序确定了单个作业的一致性和适用性。水泥浆的设计经过精心定制，并进行了详细的计算机辅助模拟，以确保在不影响作业目标的情况下完成固井作业。结果，DBOC概念在马来西亚的三口大斜度开发井中首次成功实施，从而简化了固井作业。最近与马来西亚一家大型国家石油公司(NOC)进行了合作，讨论了在具有挑战性的井筒环境中实现HC段非常规离线固井目标，同时最大限度地减少钻机时间并保持安全标准。本文讨论了遇到的各种挑战，目的是分享信息和行业经验教训。DBOC系统的应用可能会改变游戏规则，与目前使用的常规钻井平台固井相比，它提供了显著的变化。
{"title":"Malaysia's First Use of Subsea Release Plug System for Dual Barrier Offline Cementing (DBOC) Across Hydrocarbon Section Helps Streamline Activities","authors":"Ashikin Kamaludin, M. S. M Ariffin, Lau Chee Hen, Avinash Kishore Kumar, Aizat Noh","doi":"10.2523/iptc-22854-ms","DOIUrl":"https://doi.org/10.2523/iptc-22854-ms","url":null,"abstract":"\u0000 Completing primary cementing operations under the rig floor (also known as offline cementing) instead of conventional cementing is an emerging approach that continues to gain industry interest. This is because of the opportunity this method presents for reducing operational flat time and optimizing rig use, resulting in significant cost savings.\u0000 It is essential to relate the concept of offline cementing with regards to hydrocarbons (HCs) presence in the formation. Offline cementing is a straightforward method when there are no HCs present in the wellbore and when the pore pressure is at hydrostatic. A single barrier in the form of overbalance mud weight is acceptable for this condition. However, when HCs are present and/or over-pressured formation, a dual barrier (mechanical and Kill Weight Mud, KWM) is necessary to help prevent uncontrolled influx from the borehole to the external environment. During the Malaysian operation discussed here, this barrier requirement was also essential to local regulatory procedures and guidelines for upstream activities as well as the operating company's technical standard for well barriers and integrity. Thus, two well barriers were required during all well activities and operations.\u0000 A dual barrier offline cementing (DBOC) system with special application of Treating Iron Works Valves (TIW Valves) and a Subsea Release (SSR) plug set was constructed to enable offline cementing within the HC section. This concept not only allowed cementing job to be executed, but at the same time allows other offline drilling activities, such as surface equipment rig-up, pressure testing lines, pre-job circulation, and cementing operations to be done while at the same time maintaining the two-barrier requirement while the blowout preventer (BOP) is removed.\u0000 A new set of challenges were encountered while completing offline cementing across a HC section. Because the environment for placing a competent cement slurry was not optimal, the quality of the wellbore seal could have potentially been affected. Thus, a tailored job procedure coupled with continuous engagement between the operating company, service partners and rig owner (through joint risk-assessment sessions) established alignment and suitability of individual operations. The cement slurry design was carefully tailored, and a detailed computer aided simulation was performed to help ensure cementing operations could be accomplished without compromising operational objectives. As a result, the DBOC concept was successfully implemented for the first time in Malaysia across three highly deviated development wells, thus streamlining cementing activities.\u0000 A recent collaboration in a major Malaysian National Oil Company (NOC) is highlighted, discussing the materialization of unconventional offline cementing objectives across a HC section in a challenging wellbore environment while minimizing rig time and maintaining safety standards. Various challenges encountered are discussed","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114993554","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}
Mangala is a large low salinity, high quality fluvial oil field reservoir in India with STOIIP of over one billion barrels of waxy and moderately viscous crude. Aqueous based chemical EOR has been identified as the most suitable technique to improve recovery over waterflooding. The objective of paper is to describe the ASP formulation development journey for Mangala which involved more than 30 corefloods till date with evolution of formulation design changing over time. The final selected formulation has been successfully tested in upper layer of Mangala field during pilot and is being planned to be used in full field. Initial formulation design was done using IFT (interfacial tension) and adsorption measurements approach. Later the formulation design was done using classic phase behavior approach which allowed quick and robust evaluation of large number of chemicals in a short duration. Typically, the formulation development involves phase behavior tests, aqueous stability test, salinity gradient design, dead oil and live oil coreflood on long linear synthetic and reservoir core plugs. A successful formulation shall have low viscous microemulsion phase, solubilization ratio greater than 10 (lower IFT), very low residual oil saturation, good thermal and aqueous stability, low adsorption, low chemical concentration and number of components among many other parameters. Initial formulation basis IFT was selected and tested under coreflood (IPTC 12636). Later, basis the phase behavior approach, another formulation consisting of 0.3% surfactant and 0.3% co-solvent was formulated (SPE 129046). For Mangala, solubilizing paraffinic waxy crude required usage of large carbon chained Alkyl Benzene Sulfonate. Formulation with hydrophobic surfactant required addition of a hydrophilic surfactant and a co-solvent. Co-solvents, though improve electrolytic strength, add significant chemical cost and are some-times unstable. Finally, a highly hydrophilic alcohol alkoxy sulfate was selected to substitute the role of co-solvent but still maintain enough electrolytic strength and the formulation consisted of 0.3% surfactant and 3% alkali and 0.25% polymer in soft water which was used during very successful pilot (SPE 179700). The formulation has been further optimized to reduce the overall chemical quantity during full field (SPE 200445) with 0.25% surfactant and 2.5% alkali. Additionally, formulation has been further validated on other layers of Mangala field under high pressure live oil phase behavior and live oil reservoir coreflood. This paper discusses ASP formulation development approach, technical requirement, development journey of formulation for successful Mangala ASP pilot involving more than 30 long linear corefloods under reservoir dead and live oil condition, optimization efforts undertaken to reduce the chemical usage and validation of formulation for other layers of Mangala reservoir. This paper also briefly discusses lab quality control guidelines
{"title":"ASP Formulation Development Journey, Optimisation, Validation and Quality Control for Mangala Field","authors":"Nitish Koduru, Dhruva Prasad, A. Pandey","doi":"10.2523/iptc-22729-ms","DOIUrl":"https://doi.org/10.2523/iptc-22729-ms","url":null,"abstract":"Mangala is a large low salinity, high quality fluvial oil field reservoir in India with STOIIP of over one billion barrels of waxy and moderately viscous crude. Aqueous based chemical EOR has been identified as the most suitable technique to improve recovery over waterflooding. The objective of paper is to describe the ASP formulation development journey for Mangala which involved more than 30 corefloods till date with evolution of formulation design changing over time. The final selected formulation has been successfully tested in upper layer of Mangala field during pilot and is being planned to be used in full field.\u0000 Initial formulation design was done using IFT (interfacial tension) and adsorption measurements approach. Later the formulation design was done using classic phase behavior approach which allowed quick and robust evaluation of large number of chemicals in a short duration. Typically, the formulation development involves phase behavior tests, aqueous stability test, salinity gradient design, dead oil and live oil coreflood on long linear synthetic and reservoir core plugs. A successful formulation shall have low viscous microemulsion phase, solubilization ratio greater than 10 (lower IFT), very low residual oil saturation, good thermal and aqueous stability, low adsorption, low chemical concentration and number of components among many other parameters.\u0000 Initial formulation basis IFT was selected and tested under coreflood (IPTC 12636). Later, basis the phase behavior approach, another formulation consisting of 0.3% surfactant and 0.3% co-solvent was formulated (SPE 129046). For Mangala, solubilizing paraffinic waxy crude required usage of large carbon chained Alkyl Benzene Sulfonate. Formulation with hydrophobic surfactant required addition of a hydrophilic surfactant and a co-solvent. Co-solvents, though improve electrolytic strength, add significant chemical cost and are some-times unstable. Finally, a highly hydrophilic alcohol alkoxy sulfate was selected to substitute the role of co-solvent but still maintain enough electrolytic strength and the formulation consisted of 0.3% surfactant and 3% alkali and 0.25% polymer in soft water which was used during very successful pilot (SPE 179700).\u0000 The formulation has been further optimized to reduce the overall chemical quantity during full field (SPE 200445) with 0.25% surfactant and 2.5% alkali. Additionally, formulation has been further validated on other layers of Mangala field under high pressure live oil phase behavior and live oil reservoir coreflood. This paper discusses ASP formulation development approach, technical requirement, development journey of formulation for successful Mangala ASP pilot involving more than 30 long linear corefloods under reservoir dead and live oil condition, optimization efforts undertaken to reduce the chemical usage and validation of formulation for other layers of Mangala reservoir. This paper also briefly discusses lab quality control guidelines","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125023353","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}
Wenyi Tong, Suman Kar, Hasmi Bin Taib, Azam Bin Abdul Rahman
The objective of the paper is to demonstrate digitalization of Floating Structures Integrity Management Program (FSIMP) and its application for the structural integrity of floating structure assets. The framework of FSIMP is being developed by adopting Risk Based Inspection (RBI) methodology and complemented with technical know-how and industry best-practices. Implementing the methodology provides strategic planning for maintenance by reducing the anticipated risk. Hence, ensuring uninterrupted service of the floating structure assets throughout the service life. This paper presents a systematic approach for digitalization of the integrity management program for a nominated floating structure asset. The methodology offers a procedure to acquire necessary data management gathering, risk assessment, and RBI survey plan to maintain the structural integrity in the centralized web-based platform of FSIMP. RBI process is adopted into the FSIMP to investigate all deterioration and failure mechanisms. These structures will be identified by qualitative and quantitative risk assessment methods. The implementation of FSIMP offers a wide range of capabilities in structural integrity management such as integrating all floating structure fleet assets in a single dashboard of web-based platform, clear line of sight for reliable structural integrity, and an holistic overview across all levels of management. FSIMP with RBI methodology evaluates all data gathering to optimize inspection resources based on the risk assessment through an optimum combination of inspection methods and frequencies. The whole process is aligned to the requirements from Classification to ensure reliability for continuous operations. It also observes the essential need of digitalization for FSIMP during the time of post-COVID19 pandemic and the ever-expanding offshore oil, gas and energy frontiers that demand the adoption of new and advanced technologies, especially in the field of digitalization. It is shown that FSIMP has great potential as a digitalization tool and system to integrate with the RBI risk assessment that aligns to the requirements from Classification. It is strategically to maximize the effectiveness and improved efficiency for inspection and monitoring plan. The paper provides information on the solution of digitalization to the Floating Structures Integrity Management Program (FSIMP) in ensuring that the integrity of floating structure asset during the service life is intact for continuous operation and a holistic overview for all the assigned fleet assets in a centralized dashboard web-based platform. In addition to that, RBI is as added benefit to the FSIMP with its structure methodology of data evaluation and risk assessment in order to objectively optimizing inspection and maintenance resources.
{"title":"Floating Structure Integrity Management Program (FSIMP) Towards Digitalization","authors":"Wenyi Tong, Suman Kar, Hasmi Bin Taib, Azam Bin Abdul Rahman","doi":"10.2523/iptc-22857-ms","DOIUrl":"https://doi.org/10.2523/iptc-22857-ms","url":null,"abstract":"\u0000 The objective of the paper is to demonstrate digitalization of Floating Structures Integrity Management Program (FSIMP) and its application for the structural integrity of floating structure assets. The framework of FSIMP is being developed by adopting Risk Based Inspection (RBI) methodology and complemented with technical know-how and industry best-practices. Implementing the methodology provides strategic planning for maintenance by reducing the anticipated risk. Hence, ensuring uninterrupted service of the floating structure assets throughout the service life.\u0000 This paper presents a systematic approach for digitalization of the integrity management program for a nominated floating structure asset. The methodology offers a procedure to acquire necessary data management gathering, risk assessment, and RBI survey plan to maintain the structural integrity in the centralized web-based platform of FSIMP. RBI process is adopted into the FSIMP to investigate all deterioration and failure mechanisms. These structures will be identified by qualitative and quantitative risk assessment methods.\u0000 The implementation of FSIMP offers a wide range of capabilities in structural integrity management such as integrating all floating structure fleet assets in a single dashboard of web-based platform, clear line of sight for reliable structural integrity, and an holistic overview across all levels of management. FSIMP with RBI methodology evaluates all data gathering to optimize inspection resources based on the risk assessment through an optimum combination of inspection methods and frequencies. The whole process is aligned to the requirements from Classification to ensure reliability for continuous operations. It also observes the essential need of digitalization for FSIMP during the time of post-COVID19 pandemic and the ever-expanding offshore oil, gas and energy frontiers that demand the adoption of new and advanced technologies, especially in the field of digitalization. It is shown that FSIMP has great potential as a digitalization tool and system to integrate with the RBI risk assessment that aligns to the requirements from Classification. It is strategically to maximize the effectiveness and improved efficiency for inspection and monitoring plan.\u0000 The paper provides information on the solution of digitalization to the Floating Structures Integrity Management Program (FSIMP) in ensuring that the integrity of floating structure asset during the service life is intact for continuous operation and a holistic overview for all the assigned fleet assets in a centralized dashboard web-based platform. In addition to that, RBI is as added benefit to the FSIMP with its structure methodology of data evaluation and risk assessment in order to objectively optimizing inspection and maintenance resources.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122577475","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. Henglai, R. Laochamroonvorapongse, Naruttee Kovitkanit, Takonporn Kunpitaktakun
With the determination towards sustainable growth, PTTEP has a commitment to achieve Net Zero Greenhouse Gas Emissions by 2050. Therefore, the Carbon Capture Utilization and Storage (CCUS) project in the Gulf of Thailand was initiated to evaluate the CO2 storage capacity in Bongkot and Arthit fields. Three categories of storage potential were considered including shallow aquifers and depleted gas reservoirs together with storage potential in oil rim reservoirs by using CO2 enhanced oil recovery (CO2-EOR) method. The storage potential in shallow aquifer was targeted on porous rock located between seabed and top producing reservoirs which were identified in seismic and/or well data and reached by existing platforms. For the inventory of depleted gas reservoirs, the cumulative gas production volume was allocated to an individual reservoir, which signified storage size and injectivity of reservoir. The depleted gas reservoirs were focused on ones where a great amount of gas has been produced. For the CO2-EOR candidates, all oil rim reservoirs were reviewed and included in the study. The calculation of oil gain, CO2 injection requirement, and CO2 storage potential were based on the statistical data of Water-Alternating-CO2 fields. The inventory of CO2 storage potential from three categories were compiled with the information of 1) platform name, 2) remaining reserves, 3) distance from processing platforms, and 4) CO2 storage volume. After considering the CO2 storage potential, two platforms were considered as the most suitable for two fields equipped with CO2 removal units. In addition, the CCS development study considered an option to improve CO2 removal performance of the membrane in order to recover more hydrocarbon from flared gas. After the preliminary technical evaluation, the detailed study with reservoir simulation will be conducted in order to ensure the injectivity at reservoir level, the optimization of injection well number, and the integrity of containment. The injection plan will be formulated, and the investment cost estimation of CCS project can be refined accordingly. This CCUS study was initiated to reduce the CO2 emission from production fields under PTTEP. Currently, there are more than 20 CCUS projects around the world with only a few projects at the stage of CO2 injection. It requires good collaboration among subsurface and surface teams to increase confidence in storage suitability assessment. This project provides an example of multi-disciplinary integration and robust workflow starting from CO2 storage identification, volume calculation, to candidate ranking for further detail study.
{"title":"Feasibility Study of Carbon Capture Utilization and Storage (CCUS) in the Gulf of Thailand: Phase I Storage Potential Identification","authors":"P. Henglai, R. Laochamroonvorapongse, Naruttee Kovitkanit, Takonporn Kunpitaktakun","doi":"10.2523/iptc-22951-ea","DOIUrl":"https://doi.org/10.2523/iptc-22951-ea","url":null,"abstract":"\u0000 With the determination towards sustainable growth, PTTEP has a commitment to achieve Net Zero Greenhouse Gas Emissions by 2050. Therefore, the Carbon Capture Utilization and Storage (CCUS) project in the Gulf of Thailand was initiated to evaluate the CO2 storage capacity in Bongkot and Arthit fields. Three categories of storage potential were considered including shallow aquifers and depleted gas reservoirs together with storage potential in oil rim reservoirs by using CO2 enhanced oil recovery (CO2-EOR) method.\u0000 The storage potential in shallow aquifer was targeted on porous rock located between seabed and top producing reservoirs which were identified in seismic and/or well data and reached by existing platforms. For the inventory of depleted gas reservoirs, the cumulative gas production volume was allocated to an individual reservoir, which signified storage size and injectivity of reservoir. The depleted gas reservoirs were focused on ones where a great amount of gas has been produced. For the CO2-EOR candidates, all oil rim reservoirs were reviewed and included in the study. The calculation of oil gain, CO2 injection requirement, and CO2 storage potential were based on the statistical data of Water-Alternating-CO2 fields.\u0000 The inventory of CO2 storage potential from three categories were compiled with the information of 1) platform name, 2) remaining reserves, 3) distance from processing platforms, and 4) CO2 storage volume. After considering the CO2 storage potential, two platforms were considered as the most suitable for two fields equipped with CO2 removal units. In addition, the CCS development study considered an option to improve CO2 removal performance of the membrane in order to recover more hydrocarbon from flared gas. After the preliminary technical evaluation, the detailed study with reservoir simulation will be conducted in order to ensure the injectivity at reservoir level, the optimization of injection well number, and the integrity of containment. The injection plan will be formulated, and the investment cost estimation of CCS project can be refined accordingly.\u0000 This CCUS study was initiated to reduce the CO2 emission from production fields under PTTEP. Currently, there are more than 20 CCUS projects around the world with only a few projects at the stage of CO2 injection. It requires good collaboration among subsurface and surface teams to increase confidence in storage suitability assessment. This project provides an example of multi-disciplinary integration and robust workflow starting from CO2 storage identification, volume calculation, to candidate ranking for further detail study.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125180817","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}
Husam R. Abbood, Ethar H. K. Alkamil, Karrar Riyad Miftah Miftah, Amgad Hamad Khalaf Al Dhaheri, Ibrahim Salim Abdullah Al Luaibi, Muhammed Adnan Khudhaier Almaarij, Ali Hassan Jaber Alhilfi, Zamzam Neama Hamad Hamad
The oil and gas industry is witnessing an increasing demand for more cost-effective well design and operations. Thus, the scope of the operator company's planned new processing capacity aims to attain a competitive cost and schedule. In this work, slim versus fat casing designs are evaluated in price and technical challenges, including removing rig/skidding, drilling, and ensuring well suspension. Data from ten (five slim design and five fat design) wells in southern Iraq was quantitatively analyzed. Attaining the project's target requires that the well be drilled as a deviated well (S-type). The analysis includes the cost of CSG, lost circulation, lost curing, lost circulation materials, volume of the cement plugs to cure losses, non-productive time, stuck pipe and differential sticking, and cement bond quality. Moreover, a cost analysis is conducted by considering all of a project's relevant factors—including economic and technical considerations—to ascertain the likelihood of completing the project. The finding emerged that the amount of lost mud and the average cost of addressing losses were higher in slim than fat designs. The slim design is associated with higher volumes of cement plugs for curing losses than the fat design. As per NPT analysis, the time required to fix losses emanating from slim design was 62% higher than fat design. A critical observation emerged from the study that while differential sticking failed to occur in both designs, stuck pipes happened in some of both designs. The cost analysis of slim and fat designs focused on the cost of drilling, CSG, wellhead, diesel, and fueling is also done. The total cost of the fat design amounted to approximately 53.67%, while the total cost of the slim design was about 46.33%. This made the slim design's cost savings ratio of roughly 7.34%. Meanwhile, given that similar issues may occur in the proposed well design, the following measures have been isolated to help tackle such problems. (1) Optimize mud design to inhibit Tanuma formation Clay swelling issues (2) Reduce OH time to avoid Tanuma's time-dependent clay swelling. (3) Reduce the inclination across Tanuma to 20 degrees. Finally, this paper describes how two casing designs are successfully engineered and executed and serves as a guide for selecting proper candidates for this design. Also, it is an operational guide for two casing designs, slim and fat, to ensure that these challenging long open holes will be successfully and economically drilled while minimizing risks and ensuring compliance with the well delivery process.
{"title":"Sensitivity Analysis and Cost Analysis for Casing Designs (Case study)","authors":"Husam R. Abbood, Ethar H. K. Alkamil, Karrar Riyad Miftah Miftah, Amgad Hamad Khalaf Al Dhaheri, Ibrahim Salim Abdullah Al Luaibi, Muhammed Adnan Khudhaier Almaarij, Ali Hassan Jaber Alhilfi, Zamzam Neama Hamad Hamad","doi":"10.2523/iptc-22866-ms","DOIUrl":"https://doi.org/10.2523/iptc-22866-ms","url":null,"abstract":"\u0000 The oil and gas industry is witnessing an increasing demand for more cost-effective well design and operations. Thus, the scope of the operator company's planned new processing capacity aims to attain a competitive cost and schedule. In this work, slim versus fat casing designs are evaluated in price and technical challenges, including removing rig/skidding, drilling, and ensuring well suspension.\u0000 Data from ten (five slim design and five fat design) wells in southern Iraq was quantitatively analyzed. Attaining the project's target requires that the well be drilled as a deviated well (S-type). The analysis includes the cost of CSG, lost circulation, lost curing, lost circulation materials, volume of the cement plugs to cure losses, non-productive time, stuck pipe and differential sticking, and cement bond quality. Moreover, a cost analysis is conducted by considering all of a project's relevant factors—including economic and technical considerations—to ascertain the likelihood of completing the project.\u0000 The finding emerged that the amount of lost mud and the average cost of addressing losses were higher in slim than fat designs. The slim design is associated with higher volumes of cement plugs for curing losses than the fat design. As per NPT analysis, the time required to fix losses emanating from slim design was 62% higher than fat design. A critical observation emerged from the study that while differential sticking failed to occur in both designs, stuck pipes happened in some of both designs. The cost analysis of slim and fat designs focused on the cost of drilling, CSG, wellhead, diesel, and fueling is also done. The total cost of the fat design amounted to approximately 53.67%, while the total cost of the slim design was about 46.33%. This made the slim design's cost savings ratio of roughly 7.34%. Meanwhile, given that similar issues may occur in the proposed well design, the following measures have been isolated to help tackle such problems. (1) Optimize mud design to inhibit Tanuma formation Clay swelling issues (2) Reduce OH time to avoid Tanuma's time-dependent clay swelling. (3) Reduce the inclination across Tanuma to 20 degrees.\u0000 Finally, this paper describes how two casing designs are successfully engineered and executed and serves as a guide for selecting proper candidates for this design. Also, it is an operational guide for two casing designs, slim and fat, to ensure that these challenging long open holes will be successfully and economically drilled while minimizing risks and ensuring compliance with the well delivery process.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131514927","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}
Severe corrosion phenomena is easily occurred on offshore pipelines especially in splash zone section. This zone needs to be closely monitored and inspected by Magnetic Flux Leakage (MFL) pigging method. Nevertheless, the MFL pig can run faster than the required speed to obtain the best inspected data or the ordometers of MFL pig lift off from the pipeline wall thickness during running in the vertical position. If there are any defects which can be directly inspected by Non Destructive Test (NDT) method, this result can be used to calibrate the MFL signal to minimize the errors from the speed excursion. In general, MFL pigging technology is usually used to inspect the metal loss of natural gas pipelines. There are many external corrosions which scatter throughout the pipeline surface in each piggable pipelines. Most of the severe external corrosions are the significant and large defects which directly affect to the pipeline remaining strength. These defects are generally located on the pipeline section above the water surface. Some of them can be also locates underneath the composite wrap that are quite difficult to be verified. However, there is some defects which can be directly inspected by pit depth gauge. This valuable defect sizes are used for calibration of the other defect sizes in some hard spots of inspections. After receiving the final report of MFL in 2021, the position of the new growth of corrosion defects underneath the original composite wrap and the new external corrosion feature in the surrounding area are located. The current corrosion defect found in the 2021 MFL report are compared with defects found in year 2014, 2007, 2004 and 1992. For the maximum depth of corrosion defect in 2021 MFL report, the remaining strength of this defect based on ASME B31G in longitudinal defect and Kastner in circumferential axis are assessed. The assessment of maximum allowable operating pressure (MAOP) remained lower than the current maximum allowable operating pressure. This new MAOP was directly afflected to the gas deliverable to customers and require PTT to verify the defects by NDT methods and repair it with the recommended repairing method according to Pipeline Research Council International (PRCI). This repair could support to maintain the current MAOP without any reduction on MAOP. In the same way, PTT measured the external corrosion in the exposed area above the original composite wrap and revert the defect dimension to ILI vendor in order to recalibrate its dimension. Then, the ILI vendor reassessed the defect dimension depended on the actual dimension from field measurement. Mostly, the new defect depths was smaller than the first issue of final report in 2021. The ILI vendor submitted the new version of final report. For the reparing history at riser section, this riser section was revamped by pipe wrap in 2003 because it contained localized corrosion with the depth of 3-5 mm, the width of 400 mm and the length of 200 mm. Afte
{"title":"The Calibration Method to Improve the Data Quality of Defect in Term of Size Deviation on Natural Gas Pipelines Inspected by MFL Pigging Method","authors":"Kitisiri Khajornkai, Homhual Navasin, Nenkaew Piman","doi":"10.2523/iptc-22936-ea","DOIUrl":"https://doi.org/10.2523/iptc-22936-ea","url":null,"abstract":"\u0000 Severe corrosion phenomena is easily occurred on offshore pipelines especially in splash zone section. This zone needs to be closely monitored and inspected by Magnetic Flux Leakage (MFL) pigging method. Nevertheless, the MFL pig can run faster than the required speed to obtain the best inspected data or the ordometers of MFL pig lift off from the pipeline wall thickness during running in the vertical position. If there are any defects which can be directly inspected by Non Destructive Test (NDT) method, this result can be used to calibrate the MFL signal to minimize the errors from the speed excursion.\u0000 In general, MFL pigging technology is usually used to inspect the metal loss of natural gas pipelines. There are many external corrosions which scatter throughout the pipeline surface in each piggable pipelines. Most of the severe external corrosions are the significant and large defects which directly affect to the pipeline remaining strength. These defects are generally located on the pipeline section above the water surface. Some of them can be also locates underneath the composite wrap that are quite difficult to be verified. However, there is some defects which can be directly inspected by pit depth gauge. This valuable defect sizes are used for calibration of the other defect sizes in some hard spots of inspections.\u0000 After receiving the final report of MFL in 2021, the position of the new growth of corrosion defects underneath the original composite wrap and the new external corrosion feature in the surrounding area are located. The current corrosion defect found in the 2021 MFL report are compared with defects found in year 2014, 2007, 2004 and 1992. For the maximum depth of corrosion defect in 2021 MFL report, the remaining strength of this defect based on ASME B31G in longitudinal defect and Kastner in circumferential axis are assessed. The assessment of maximum allowable operating pressure (MAOP) remained lower than the current maximum allowable operating pressure. This new MAOP was directly afflected to the gas deliverable to customers and require PTT to verify the defects by NDT methods and repair it with the recommended repairing method according to Pipeline Research Council International (PRCI). This repair could support to maintain the current MAOP without any reduction on MAOP.\u0000 In the same way, PTT measured the external corrosion in the exposed area above the original composite wrap and revert the defect dimension to ILI vendor in order to recalibrate its dimension. Then, the ILI vendor reassessed the defect dimension depended on the actual dimension from field measurement. Mostly, the new defect depths was smaller than the first issue of final report in 2021. The ILI vendor submitted the new version of final report.\u0000 For the reparing history at riser section, this riser section was revamped by pipe wrap in 2003 because it contained localized corrosion with the depth of 3-5 mm, the width of 400 mm and the length of 200 mm. Afte","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"123 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127060228","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}
Monaf S. Alaithan, Jairo Alonso Leal Jauregui, Waleed Ahmed Al-Hazmi, S. Sarac
Flowback operation of ultra-high H2S gas well is a challenging scenario due to complex environmental considerations, equipment limitations and limitations on surface flow management with unstable well conditions. This paper will present an application where flaring impacts were significantly minimized and no H2S gas was released to the atmosphere, unlocking the production potential of high-H2S formations. Then, a new Technology concept is being developed. A brand new Closed-Loop Testing package has been implemented to overcome the flowback limitations with high H2S concentration and minimize flaring during well clean-up. Simulation results of expected wellbore dynamics during well start-up were studied to optimize flowback package fluid handling capacity and perform safe operating conditions. New inline measurement devices were used for H2S, CO2 and inline density measurement were key on providing in-line well monitoring parameters as well as better decision points and control in key elements and including; new control valve metallurgy, new metal-meat seals, new PRV design/metallurgies, new EE-NL pipeline, new approach in low pressure systems, pressurized storage vessels both condensate and water, as well as avoid any human exposure for critical procedure including water, PVT sampling and gas metering validations. This new approach allows to complete this task without releasing toxic gases to the atmosphere. Selected equipment also allowed continuous flow to clean-up the wellbore and safely transfer the fluids to the production line, minimizing flaring while avoiding any environmental impact. Wellbore behavior during well kick-off was as expected based on the transient wellbore and reservoir simulations, which helped achieve a continuous flow to safely flow the wellbore and handle the produced fluids. The selected closed-loop testing set-up in addition to continuous well monitoring with new inline measurement devices allowed remarkable flow management optimization. This reduced CO2 and toxic gas emissions, minimizing environmental impact. Toxic gas release in the flowback area was also avoided by eliminating manual measurements with the closed-loop testing package. The wellbore was cleaned-up to achieve the production tie-in criteria. This implementation acts as a proof of concept to flowback high-H2S wells. This paper presents the new testing equipment and practices to enable safe flowback in high and ultra-high H2S conditions. The example explained in this paper is the first post-stimulation wellbore flowback in Saudi Arabia, including ultra-high H2S conditions being achieve by a new closed-loop well-testing package.
{"title":"Unlocking Gas Production Potential for Ultra-High H2S Reservoirs: Closed-Loop Testing Avoids Flaring and Toxic Gas Release","authors":"Monaf S. Alaithan, Jairo Alonso Leal Jauregui, Waleed Ahmed Al-Hazmi, S. Sarac","doi":"10.2523/iptc-22915-ms","DOIUrl":"https://doi.org/10.2523/iptc-22915-ms","url":null,"abstract":"\u0000 Flowback operation of ultra-high H2S gas well is a challenging scenario due to complex environmental considerations, equipment limitations and limitations on surface flow management with unstable well conditions. This paper will present an application where flaring impacts were significantly minimized and no H2S gas was released to the atmosphere, unlocking the production potential of high-H2S formations.\u0000 Then, a new Technology concept is being developed. A brand new Closed-Loop Testing package has been implemented to overcome the flowback limitations with high H2S concentration and minimize flaring during well clean-up. Simulation results of expected wellbore dynamics during well start-up were studied to optimize flowback package fluid handling capacity and perform safe operating conditions. New inline measurement devices were used for H2S, CO2 and inline density measurement were key on providing in-line well monitoring parameters as well as better decision points and control in key elements and including; new control valve metallurgy, new metal-meat seals, new PRV design/metallurgies, new EE-NL pipeline, new approach in low pressure systems, pressurized storage vessels both condensate and water, as well as avoid any human exposure for critical procedure including water, PVT sampling and gas metering validations. This new approach allows to complete this task without releasing toxic gases to the atmosphere. Selected equipment also allowed continuous flow to clean-up the wellbore and safely transfer the fluids to the production line, minimizing flaring while avoiding any environmental impact.\u0000 Wellbore behavior during well kick-off was as expected based on the transient wellbore and reservoir simulations, which helped achieve a continuous flow to safely flow the wellbore and handle the produced fluids. The selected closed-loop testing set-up in addition to continuous well monitoring with new inline measurement devices allowed remarkable flow management optimization. This reduced CO2 and toxic gas emissions, minimizing environmental impact. Toxic gas release in the flowback area was also avoided by eliminating manual measurements with the closed-loop testing package. The wellbore was cleaned-up to achieve the production tie-in criteria. This implementation acts as a proof of concept to flowback high-H2S wells.\u0000 This paper presents the new testing equipment and practices to enable safe flowback in high and ultra-high H2S conditions. The example explained in this paper is the first post-stimulation wellbore flowback in Saudi Arabia, including ultra-high H2S conditions being achieve by a new closed-loop well-testing package.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124483188","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}
Ali Hijles, Fauzia Waluyo, Kamaljeet Singh, Abderrahmane Benslimani
More wells are being completed with fiberglass casings to overcome the challenge of corrosion to the carbon steel casings. Fiberglass casing is expected to increase the longevity of the wells. The wells completed with fiberglass still require the operators to confirm that the casing is in good condition and also the annular cement sheath is able to provide mechanical support and zonal isolation. The evaluation poses a challenge as the properties of the fiberglass are very different to that of the carbon steel casing. Some studies were performed in 2018 to test the ultrasonic physics in fiberglass, this paper will describe the challenges and how we have now developed an innovative data acquisition, processing and interpretation workflow to properly evaluate both the fiberglass casing condition and as well the annular cement condition. It was observed through surface experiments that the conventional ultrasonic technique applicable to carbon steel pipes has been proven to be invalid in fiberglass casings because the velocity and acoustic impedance of fiberglass are much lower than steel; therefore, there is no resonance in fiberglass. A new interpretation workflow was developed and applied to raw data to build specific parameters proper to the fiberglass samples to determine the acoustic properties: acoustic impedance, attenuation factor and velocity. It is for the first time that data has been acquired in a very large fiberglass casing. Fiberglass casings were run in water well, and wireline acoustic logs were successfully acquired for cement and corrosion evaluation across 19-inch. OD Glass Reinforced Epoxy pipes. The interpretation workflow was applied to raw field data and a comprehensive cement map and corrosion answer products were obtained with an acceptable quality control level. The paper will review the data from three wells. This innovative data acquisition, processing, and interpretation workflow can be deployed in wells for decision making prior to completion and production. The new method also opens up future opportunities for the evaluation of non-carbon steel pipes, and with knowledge of mechanical and acoustic properties, the method can be adapted to perform a full evaluation. This method is expected to provide valuable information for wells planned to be completed with fiberglass casing.
{"title":"Innovative Approach to Enhanced Well Integrity Evaluation in Unconventional Completions with Fiberglass Casings","authors":"Ali Hijles, Fauzia Waluyo, Kamaljeet Singh, Abderrahmane Benslimani","doi":"10.2523/iptc-22851-ea","DOIUrl":"https://doi.org/10.2523/iptc-22851-ea","url":null,"abstract":"\u0000 More wells are being completed with fiberglass casings to overcome the challenge of corrosion to the carbon steel casings. Fiberglass casing is expected to increase the longevity of the wells. The wells completed with fiberglass still require the operators to confirm that the casing is in good condition and also the annular cement sheath is able to provide mechanical support and zonal isolation. The evaluation poses a challenge as the properties of the fiberglass are very different to that of the carbon steel casing. Some studies were performed in 2018 to test the ultrasonic physics in fiberglass, this paper will describe the challenges and how we have now developed an innovative data acquisition, processing and interpretation workflow to properly evaluate both the fiberglass casing condition and as well the annular cement condition.\u0000 It was observed through surface experiments that the conventional ultrasonic technique applicable to carbon steel pipes has been proven to be invalid in fiberglass casings because the velocity and acoustic impedance of fiberglass are much lower than steel; therefore, there is no resonance in fiberglass. A new interpretation workflow was developed and applied to raw data to build specific parameters proper to the fiberglass samples to determine the acoustic properties: acoustic impedance, attenuation factor and velocity. It is for the first time that data has been acquired in a very large fiberglass casing.\u0000 Fiberglass casings were run in water well, and wireline acoustic logs were successfully acquired for cement and corrosion evaluation across 19-inch. OD Glass Reinforced Epoxy pipes. The interpretation workflow was applied to raw field data and a comprehensive cement map and corrosion answer products were obtained with an acceptable quality control level. The paper will review the data from three wells.\u0000 This innovative data acquisition, processing, and interpretation workflow can be deployed in wells for decision making prior to completion and production. The new method also opens up future opportunities for the evaluation of non-carbon steel pipes, and with knowledge of mechanical and acoustic properties, the method can be adapted to perform a full evaluation. This method is expected to provide valuable information for wells planned to be completed with fiberglass casing.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121744269","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}
Yi Pan, Kyle Vrnak, Juan Carlos Fierro, Meyar Shehab, Saurabh Arora, F. Al-Mutawa, N. Al-Barazi
Access to develop new drill bit technologies are increasing the capabilities to improve performance in the most challenging directional applications, where the focus is to reduce any type of disfunctions that will be generated due to the interaction between the drill bit, drill string and formation compressive strength. A case study is presented to demonstrate the liability and consistency of this new technology. This paper discusses the sensing at the bit technology that has different capabilities that can be used to improve drilling performance, combining the new cutting structure in the drill bit that keeps in series the shearing and breaking actions generated by the new cutting elements, at the same time those actions are recorded by the drill bit sensor. The generated information is used to compare standard drill bits with modified designs where the advantages can be seen clearly, and at the same time new engineered technologies can be put in place to have further improvements in performance. In Kuwait, the 12 ¼" section is a challenging application in terms of directional requirements, rate of penetration and is mandatory to have the necessary stability to be able to increase the required drilling parameters that will end up with outstanding performances. A compressive engineering analysis of a customized drill bit and the implementation of the sensing at the bit data capture was used to understand the drilling parameters, drilling disfunctions and the interaction between the engineered cutting structure and the formations drilled. The data was correlated with available data from offset wells and helped to confirm the performances achieved. The detection of different disfunctions and the frequency generated for the added device was the key to understand the functionality of the tool. It showed that the new technology drill bit, in which a rolling crush-and-shear cone is incorporated to the center of a PDC bit, increases bit stability and mitigates lateral vibration while achieving outstanding performance.
{"title":"New Hybrid Technology and Sensing at the Bit Sensors Utilized in Directional Applications at North to Kuwait to Help to Identify and Minimize Disfunctions","authors":"Yi Pan, Kyle Vrnak, Juan Carlos Fierro, Meyar Shehab, Saurabh Arora, F. Al-Mutawa, N. Al-Barazi","doi":"10.2523/iptc-23088-ea","DOIUrl":"https://doi.org/10.2523/iptc-23088-ea","url":null,"abstract":"\u0000 Access to develop new drill bit technologies are increasing the capabilities to improve performance in the most challenging directional applications, where the focus is to reduce any type of disfunctions that will be generated due to the interaction between the drill bit, drill string and formation compressive strength. A case study is presented to demonstrate the liability and consistency of this new technology.\u0000 This paper discusses the sensing at the bit technology that has different capabilities that can be used to improve drilling performance, combining the new cutting structure in the drill bit that keeps in series the shearing and breaking actions generated by the new cutting elements, at the same time those actions are recorded by the drill bit sensor. The generated information is used to compare standard drill bits with modified designs where the advantages can be seen clearly, and at the same time new engineered technologies can be put in place to have further improvements in performance.\u0000 In Kuwait, the 12 ¼\" section is a challenging application in terms of directional requirements, rate of penetration and is mandatory to have the necessary stability to be able to increase the required drilling parameters that will end up with outstanding performances.\u0000 A compressive engineering analysis of a customized drill bit and the implementation of the sensing at the bit data capture was used to understand the drilling parameters, drilling disfunctions and the interaction between the engineered cutting structure and the formations drilled. The data was correlated with available data from offset wells and helped to confirm the performances achieved. The detection of different disfunctions and the frequency generated for the added device was the key to understand the functionality of the tool. It showed that the new technology drill bit, in which a rolling crush-and-shear cone is incorporated to the center of a PDC bit, increases bit stability and mitigates lateral vibration while achieving outstanding performance.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124797556","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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