Coiled Tubing (CT) operations complexity has increased exponentially in extended reach developments in the Middle East, and North and South America due to longer horizontals, however rig horsepower (HP) limitations compromise navigation control in the horizontal sections, leading to high tortuosity wells, which hinders CT accessibility. The CT Complexity Index (CTCI) aims to identify critical wells that may require special Extended Reach Tools (ERT), higher Friction Reducer (FR) concentrations, or multiple runs. Computer Assisted Engineering (CAE) software is limited to 500 lines for directional input; hence, this study considers an optimized CT design methodology based on well construction factors to continue using surveys with readings every ∼100 ft. More than 20 well interventions have been analyzed to determine what factors affect the outcome, considering factors such as: Deviation Survey Tortuosity Maximum Dogleg Severity (DLS) Horizontal length 2D or 3D wells Based on statistics, the analyzed results contributed towards developing a CTCI to anticipate possible issues during operations, such as multiple CT runs and the percentage of success in reaching Target Depth (TD). After analyzing data and job results, it was determined that, even though the CAE software shows that TD can be reached, it is possible that multiple runs would be required, or, on some occasions, it would not be possible to reach TD. This is a consequence of multiple factors related to drilling, completion, and CT operations, such as insufficient FR concentration, ERT failure, well tortuosity in the horizontal section, and the fact that the CAE software predicts buckling and CT-completion contact points based on mathematical models which are limited to 500 input lines on the directional survey tab. All of these lead to unaccounted friction forces, where these models can fail to identify some completion contact points affecting the predicted CT reach. Determining a single factor such as CTCI allows the determination ahead of time of either a modified Friction Coefficient (FC) or Paslay Helical Buckling Coefficient (PHBC) to include FR and ERT selection, multiple CT run requirement, or if there is a risk of CT not reaching TD, which in turn can improve job planning. The CTCI can be associated with an adjusted FC or PHBC, allowing more reliable CAE simulation results. The calculation of the CTCI during the planning stage will help to address properly: Technical challenges and solutions to reach TD Forecast operations and coordinate logistic requirements Additional resources (water, additives, BHA) This increases efficiencies and minimizes Non-Productive Time (NPT) related to waiting for resources.
{"title":"Deciphering the Well Complexity Index for Coiled Tubing Interventions, a Unique Factor for Better Engineering and Operational Planning","authors":"Renny Ottolina, G. Ambrosi","doi":"10.2118/218321-ms","DOIUrl":"https://doi.org/10.2118/218321-ms","url":null,"abstract":"\u0000 Coiled Tubing (CT) operations complexity has increased exponentially in extended reach developments in the Middle East, and North and South America due to longer horizontals, however rig horsepower (HP) limitations compromise navigation control in the horizontal sections, leading to high tortuosity wells, which hinders CT accessibility. The CT Complexity Index (CTCI) aims to identify critical wells that may require special Extended Reach Tools (ERT), higher Friction Reducer (FR) concentrations, or multiple runs.\u0000 Computer Assisted Engineering (CAE) software is limited to 500 lines for directional input; hence, this study considers an optimized CT design methodology based on well construction factors to continue using surveys with readings every ∼100 ft. More than 20 well interventions have been analyzed to determine what factors affect the outcome, considering factors such as:\u0000 Deviation Survey Tortuosity Maximum Dogleg Severity (DLS) Horizontal length 2D or 3D wells\u0000 Based on statistics, the analyzed results contributed towards developing a CTCI to anticipate possible issues during operations, such as multiple CT runs and the percentage of success in reaching Target Depth (TD).\u0000 After analyzing data and job results, it was determined that, even though the CAE software shows that TD can be reached, it is possible that multiple runs would be required, or, on some occasions, it would not be possible to reach TD. This is a consequence of multiple factors related to drilling, completion, and CT operations, such as insufficient FR concentration, ERT failure, well tortuosity in the horizontal section, and the fact that the CAE software predicts buckling and CT-completion contact points based on mathematical models which are limited to 500 input lines on the directional survey tab. All of these lead to unaccounted friction forces, where these models can fail to identify some completion contact points affecting the predicted CT reach.\u0000 Determining a single factor such as CTCI allows the determination ahead of time of either a modified Friction Coefficient (FC) or Paslay Helical Buckling Coefficient (PHBC) to include FR and ERT selection, multiple CT run requirement, or if there is a risk of CT not reaching TD, which in turn can improve job planning.\u0000 The CTCI can be associated with an adjusted FC or PHBC, allowing more reliable CAE simulation results.\u0000 The calculation of the CTCI during the planning stage will help to address properly:\u0000 Technical challenges and solutions to reach TD Forecast operations and coordinate logistic requirements Additional resources (water, additives, BHA)\u0000 This increases efficiencies and minimizes Non-Productive Time (NPT) related to waiting for resources.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"32 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284942","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}
Recent reports have highlighted hydrogen embrittlement (HE) of high strength, quench-and-temper (Q&T) coiled tubing (CT) resulting from hydrochloric (HCl) acid usage in sour environments. HCl acid treatments expose CT surfaces to aggressive corrosion, often exacerbated by H2S from formation fluids or as a chemical reaction. Helping the CT industry recognize the morphologies of damage when the tube is retired and re-evaluating the CT grade selection and chemicals are vital for averting costly and dangerous CT failures. To establish a comprehensive case history preceding the CT failure mode, pertinent field data must be collected and correlated, encompassing job frequency, acid and H2S exposure duration, concentration levels, downhole conditions, and inhibition procedures. Metallurgical analysis, including an exhaustive battery of tests, was conducted on the specimens: visual assessment, dimensional verification, fractography, metallographic analysis, mechanical integrity evaluation (comprising hardness and tensile testing), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy (EDS), along with sodium azide spot testing. A summary of field failures was evaluated from diverse operational environments and locations. Multiple factors contributed to premature CT retirement, particularly inadequate corrosion inhibition and sulfide scavenger programs. However, environmental conditions, operational stresses, microstructural differences, and susceptibilities of various high-grade materials (Q&T and conventional) were correlated and compared with industry research. Low pH fluids like hydrochloric acid or other acidic substances combined with H2S presence created a susceptibility for the high-grade CT materials consistent with other high strength oil and gas carbon steel materials. Material properties, specifically tensile strength and hardness showed a distinct susceptibility to HE with increasing tensile strength. Steels with tensile strengths below 140-ksi are relatively less vulnerable to HE, but susceptibility significantly escalates beyond this threshold. Typically, low cycle fatigue promoted complete through-wall crack propagation, with some cases demonstrating fatigue originating from the steel centerline, where hydrogen ions from acid tend to migrate and recombine as gas. Other initiation points include the OD/ID surfaces and the longitudinal weld. These initiation points demonstrated consistent hydrogen embrittlement intergranular failure mechanisms. Recent materials research in the Oil and Gas space related to HE and H2S exposure on materials similar to coiled tubing was evaluated for relevance. Two interesting areas of research are presented: fracture propagation theories with hydrogen presence related to fatigue environments, and the influence of various iron sulfide films resulting from the corrosion reaction of H2S and steel. Sour immersion testing results on high strength coiled tubing are also presented to demon
{"title":"Decoding Hydrogen Embrittlement in High Strength Coiled Tubing: Insights from Acid-Induced Failures, Field Data Analysis, and Corrosion Management Strategies","authors":"G. McClelland, I. Galvan, G. Mallanao, B. Watson","doi":"10.2118/218327-ms","DOIUrl":"https://doi.org/10.2118/218327-ms","url":null,"abstract":"\u0000 Recent reports have highlighted hydrogen embrittlement (HE) of high strength, quench-and-temper (Q&T) coiled tubing (CT) resulting from hydrochloric (HCl) acid usage in sour environments. HCl acid treatments expose CT surfaces to aggressive corrosion, often exacerbated by H2S from formation fluids or as a chemical reaction. Helping the CT industry recognize the morphologies of damage when the tube is retired and re-evaluating the CT grade selection and chemicals are vital for averting costly and dangerous CT failures.\u0000 To establish a comprehensive case history preceding the CT failure mode, pertinent field data must be collected and correlated, encompassing job frequency, acid and H2S exposure duration, concentration levels, downhole conditions, and inhibition procedures. Metallurgical analysis, including an exhaustive battery of tests, was conducted on the specimens: visual assessment, dimensional verification, fractography, metallographic analysis, mechanical integrity evaluation (comprising hardness and tensile testing), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy (EDS), along with sodium azide spot testing.\u0000 A summary of field failures was evaluated from diverse operational environments and locations. Multiple factors contributed to premature CT retirement, particularly inadequate corrosion inhibition and sulfide scavenger programs. However, environmental conditions, operational stresses, microstructural differences, and susceptibilities of various high-grade materials (Q&T and conventional) were correlated and compared with industry research. Low pH fluids like hydrochloric acid or other acidic substances combined with H2S presence created a susceptibility for the high-grade CT materials consistent with other high strength oil and gas carbon steel materials. Material properties, specifically tensile strength and hardness showed a distinct susceptibility to HE with increasing tensile strength. Steels with tensile strengths below 140-ksi are relatively less vulnerable to HE, but susceptibility significantly escalates beyond this threshold. Typically, low cycle fatigue promoted complete through-wall crack propagation, with some cases demonstrating fatigue originating from the steel centerline, where hydrogen ions from acid tend to migrate and recombine as gas. Other initiation points include the OD/ID surfaces and the longitudinal weld. These initiation points demonstrated consistent hydrogen embrittlement intergranular failure mechanisms.\u0000 Recent materials research in the Oil and Gas space related to HE and H2S exposure on materials similar to coiled tubing was evaluated for relevance. Two interesting areas of research are presented: fracture propagation theories with hydrogen presence related to fatigue environments, and the influence of various iron sulfide films resulting from the corrosion reaction of H2S and steel.\u0000 Sour immersion testing results on high strength coiled tubing are also presented to demon","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"55 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285059","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study delves into the implementation of an integrated completion strategy for a horizontal infill well within a gas reservoir, with a primary focus on enhancing hydrocarbon recovery. The first lateral well in the field served as a testing ground for the combined utilization of Coiled Tubing (CT) and hydraulic fracturing services aimed at optimizing completion strategies and increasing adaptability in the presence of potentially drained zones along the horizontal section. The 1.75-inch CT facilitated a rigless operation, with a calibration run ensuring tool passage through potential restrictions, leading to subsequent Abrasive Jetting (AJ) and hydraulic fracturing operations. Grounded in the well's established petrophysical and structural model, a thoughtful selection of depth facilitated the placement of a bridge plug, with Abrasive Jetting (AJ) establishing effective wellbore-reservoir communication. Diagnostic Fracture Injection Tests (DFIT) were then conducted iteratively to assess the interaction of the infill well with undrained areas. The application of pinpoint stimulation technology demonstrated its capacity to induce fractures through a minimal number of holes, allowing for increased control over initiation sites and improved fracture height coverage. This approach enhances well productivity by increasing the fracture area in contact with the formation. Practicality and cost-effectiveness were validated using CT for various well-intervention procedures, complemented by Abrasive Jetting (AJ) assisted fracturing to minimize fracture entry friction. The multi-stage operation revealed successful drainage of two zones during the intervention. The acquisition of reservoir data for simulation purposes was pivotal in shaping future field development plans and strategically placing additional lateral wells to optimize recovery factors. To maximize hydrocarbon recovery and minimize costs, the AJ process and hydraulic fracturing techniques must be carefully optimized for economic feasibility. Reservoir simulations are employed to refine treatments for future projects, leveraging insights from pressure profiles and interactions with offset wells. The lessons learned from this well provide valuable insights for upcoming lateral infill wells, contributing to the continual improvement of execution methodologies. This first infill well not only validated the hypothesis that reserves persist beyond the drainage radius of previous wells but also demonstrated a doubling of expected production levels. The success of this endeavor underscores the potential advancements in hydrocarbon recovery techniques, with implications extending beyond commercial interests to contribute to the broader understanding of reservoir dynamics and optimal well completion strategies.
本研究深入探讨了在天然气储层中为水平填充井实施综合完井战略的问题，主要重点是提高碳氢化合物的采收率。该油田的第一口横向井是综合利用盘管（CT）和水力压裂服务的试验场，旨在优化完井策略，提高水平段潜在排水区的适应性。1.75 英寸 CT 为无钻机作业提供了便利，校准运行可确保工具通过潜在的限制，从而进行后续的喷砂 (AJ) 和水力压裂作业。以油井已建立的岩石物理和构造模型为基础，深思熟虑地选择深度，有助于放置桥塞，并通过磨料喷射（AJ）建立有效的井筒-储层沟通。随后，反复进行了诊断断裂喷射试验（DFIT），以评估填充井与未排水区域的相互作用。针点增产技术的应用表明，该技术能够通过最少的钻孔诱发裂缝，从而加强对起始点的控制，提高裂缝高度覆盖率。这种方法通过增加与地层接触的裂缝面积来提高油井生产率。使用 CT 对各种油井干预程序的实用性和成本效益进行了验证，并辅以磨料喷射（AJ）辅助压裂，以最大限度地减少压裂进入摩擦。多阶段作业显示，在干预过程中成功排出了两个区域。为模拟目的获取储层数据对于制定未来油田开发计划以及战略性地增设侧向井以优化采收率至关重要。为了最大限度地提高碳氢化合物采收率并降低成本，必须仔细优化 AJ 工艺和水力压裂技术，以确保经济可行性。我们利用储层模拟来完善未来项目的处理方法，并从压力剖面以及与偏置井的相互作用中获得启示。从这口井吸取的经验教训为即将进行的横向填充井提供了宝贵的见解，有助于不断改进执行方法。第一口注水井不仅验证了储量在前几口井的排水半径之外仍然存在的假设，还证明了预期生产水平翻了一番。这项工作的成功凸显了碳氢化合物回收技术的潜在进步，其影响超出了商业利益，有助于更广泛地了解储层动态和最佳完井策略。
{"title":"Successful Selective Fractures in a Horizontal Well Demonstrate the Effectiveness of an Abrasive Jetting and Stimulation Process in Mexico","authors":"Cristian Fontana, Federico Menconi, Eber Medina, Ramiro Lugo, Raul Perez","doi":"10.2118/218361-ms","DOIUrl":"https://doi.org/10.2118/218361-ms","url":null,"abstract":"\u0000 This study delves into the implementation of an integrated completion strategy for a horizontal infill well within a gas reservoir, with a primary focus on enhancing hydrocarbon recovery. The first lateral well in the field served as a testing ground for the combined utilization of Coiled Tubing (CT) and hydraulic fracturing services aimed at optimizing completion strategies and increasing adaptability in the presence of potentially drained zones along the horizontal section.\u0000 The 1.75-inch CT facilitated a rigless operation, with a calibration run ensuring tool passage through potential restrictions, leading to subsequent Abrasive Jetting (AJ) and hydraulic fracturing operations. Grounded in the well's established petrophysical and structural model, a thoughtful selection of depth facilitated the placement of a bridge plug, with Abrasive Jetting (AJ) establishing effective wellbore-reservoir communication. Diagnostic Fracture Injection Tests (DFIT) were then conducted iteratively to assess the interaction of the infill well with undrained areas.\u0000 The application of pinpoint stimulation technology demonstrated its capacity to induce fractures through a minimal number of holes, allowing for increased control over initiation sites and improved fracture height coverage. This approach enhances well productivity by increasing the fracture area in contact with the formation. Practicality and cost-effectiveness were validated using CT for various well-intervention procedures, complemented by Abrasive Jetting (AJ) assisted fracturing to minimize fracture entry friction.\u0000 The multi-stage operation revealed successful drainage of two zones during the intervention. The acquisition of reservoir data for simulation purposes was pivotal in shaping future field development plans and strategically placing additional lateral wells to optimize recovery factors.\u0000 To maximize hydrocarbon recovery and minimize costs, the AJ process and hydraulic fracturing techniques must be carefully optimized for economic feasibility. Reservoir simulations are employed to refine treatments for future projects, leveraging insights from pressure profiles and interactions with offset wells. The lessons learned from this well provide valuable insights for upcoming lateral infill wells, contributing to the continual improvement of execution methodologies.\u0000 This first infill well not only validated the hypothesis that reserves persist beyond the drainage radius of previous wells but also demonstrated a doubling of expected production levels. The success of this endeavor underscores the potential advancements in hydrocarbon recovery techniques, with implications extending beyond commercial interests to contribute to the broader understanding of reservoir dynamics and optimal well completion strategies.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"58 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285076","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}
C. Villagrana, A. Abouganem, A. M. Afsal, M. Al-Dahhan, J. Delaune, W. R. Tapia, M. Amri
This study details a complex wire recovery operation in a live well that involved transitioning from coiled tubing (CT) to mechanical wireline (MWL), in both slickline [MA1]or braided line, to retrieve the wire in good condition and later hand it over to an electrical wireline (e-line) unit to spool it onto a drum. The operation was carried out on a live, sour gas well, demanding a unique setup and emphasizing safety. Two successful recovery operations removed a significant amount of e-line left in the well plus the upper section of the e-line bottomhole assembly (BHA) while safely pushing the lower section of the e-line BHA to the bottom of the well. An integrated, multipurpose pressure control equipment (PCE) stack provided safety and redundancy, facilitating retrieval with both CT and MWL. The PCE stack design proved robust, enabling recovery without killing the well. Notably, the operation seamlessly integrated CT, MWL, e-line, and a stimulation vessel, all utilizing the same PCE. A significant challenge involved the handover of the recovered e-line from CT to MWL, requiring careful coordination and movement to prevent stripping the retrieved e-line inside the wire-line valve rams and the risk of gas leaks. Innovatively, this operation marked the first use of downhole measurements for wire recovery alongside the application of jars and impact hammers while pumping on the backside of the coiled tubing, a pioneering approach in this context of live-well e-line recovery. Downhole measurements, particularly tension and compression readouts, aided decision-making, reducing the need for reruns. Furthermore, a downhole camera captured changes in the e-line and BHA. Overall, this operation represents an innovative achievement in wire recovery from live, sour gas wells.
{"title":"Integrated Downhole-Measurement-Enabled Coiled Tubing and Mechanical Wireline Recovery of E-Line Cable in a Live, Sour Gas Well","authors":"C. Villagrana, A. Abouganem, A. M. Afsal, M. Al-Dahhan, J. Delaune, W. R. Tapia, M. Amri","doi":"10.2118/218323-ms","DOIUrl":"https://doi.org/10.2118/218323-ms","url":null,"abstract":"\u0000 This study details a complex wire recovery operation in a live well that involved transitioning from coiled tubing (CT) to mechanical wireline (MWL), in both slickline [MA1]or braided line, to retrieve the wire in good condition and later hand it over to an electrical wireline (e-line) unit to spool it onto a drum. The operation was carried out on a live, sour gas well, demanding a unique setup and emphasizing safety. Two successful recovery operations removed a significant amount of e-line left in the well plus the upper section of the e-line bottomhole assembly (BHA) while safely pushing the lower section of the e-line BHA to the bottom of the well. An integrated, multipurpose pressure control equipment (PCE) stack provided safety and redundancy, facilitating retrieval with both CT and MWL. The PCE stack design proved robust, enabling recovery without killing the well. Notably, the operation seamlessly integrated CT, MWL, e-line, and a stimulation vessel, all utilizing the same PCE. A significant challenge involved the handover of the recovered e-line from CT to MWL, requiring careful coordination and movement to prevent stripping the retrieved e-line inside the wire-line valve rams and the risk of gas leaks. Innovatively, this operation marked the first use of downhole measurements for wire recovery alongside the application of jars and impact hammers while pumping on the backside of the coiled tubing, a pioneering approach in this context of live-well e-line recovery. Downhole measurements, particularly tension and compression readouts, aided decision-making, reducing the need for reruns. Furthermore, a downhole camera captured changes in the e-line and BHA. Overall, this operation represents an innovative achievement in wire recovery from live, sour gas wells.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"16 2‐3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395244","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Amri, R. Macaulay, S. Aboelnaga, A. Abouganem, M. Al Dahhan
Wireline operations play a crucial role in the oil and gas industry, facilitating essential tasks like well maintenance, data collection, and intervention. These operations involve deploying substantial downhole tools and large cables into the wellbore, but this endeavor is not without its challenges. Particularly, when a wireline cable breaks downhole, it poses significant risks. Unplanned wireline breakages result in demanding heavy-duty fishing operations when they occur in challenging offshore environments and unfavorable downhole conditions. In this work, strategic planning and execution were applied in a complex e-line cable recovery in a live, sour gas well without the need for well kill operations. This undertaking necessitated a unique approach to safety and setup, starting with a thorough assessment of the challenging well conditions. A comprehensive fishing plan was then developed to embrace all potential scenarios. The operation involved the use of advanced heavy-duty fishing tools and solutions specifically designed to withstand the well conditions. The success of this endeavor is evident in the completion of two recovery operations, all resulting in the successful retrieval of the wire. This first achievement enables customers to restore wellbore access and proceed with their planned interventions. One of these operations involved recovering ~ 4000ft of 5/16in Eline cable and upper section of the fish using mechanical wireline and coiled tubing. While SPE-218323-MS (ICOTA A. Abouganem 2024) provides details about the first recovery, this paper aims to present a more comprehensive overview of the second recovery. Specifically, this recovery involved retrieving a 0.350-in Polymer encapsulated wireline cable using a 5/16-in Heavy Duty braided wireline cable within a 7-in. tubing., representing the first occurrence of such a cable recovery on a global scale. The paper delves into the specific techniques employed and the substantial effort and planning invested in successfully recovering this distinctive cable, recognized for its unique shape characterized by elevated breaking strength and rigidity. The distinct nature of this recovery necessitated the utilization of specialized tools and techniques for both latching and recovery.
有线作业在石油和天然气行业发挥着至关重要的作用，为油井维护、数据收集和干预等基本任务提供便利。这些作业需要在井筒中部署大量井下工具和大型电缆，但这项工作并非没有挑战。尤其是当井下的电缆断裂时，会带来巨大的风险。在极具挑战性的海上环境和不利的井下条件下，意外断线会导致高强度的捕鱼作业。在这项工作中，战略规划和执行被应用于一个复杂的酸性气井中的电子线电缆回收，而无需进行杀井作业。这项工作需要采用独特的安全和设置方法，首先要对具有挑战性的油井条件进行全面评估。然后制定了一项全面的捕鱼计划，以应对所有可能出现的情况。作业中使用了先进的重型捕鱼工具和解决方案，这些工具和解决方案都是专门为适应油井条件而设计的。这项工作的成功体现在完成了两次打捞作业，全部成功打捞出钢丝。这第一项成果使客户能够恢复井筒通道，并继续进行计划中的干预。其中一项作业涉及使用机械钢丝绳和盘卷油管回收约 4000 英尺长的 5/16 英寸 Eline 电缆和鱼体上部。SPE-218323-MS (ICOTA A. Abouganem 2024) 提供了第一次回收的详细情况，本文旨在对第二次回收进行更全面的概述。具体而言，此次回收涉及在 7 英寸的油管中使用 5/16 英寸重型编织电缆回收 0.350 英寸聚合物封装电缆，这是全球范围内首次进行此类电缆回收。本文深入探讨了成功回收这种独特电缆所采用的具体技术，以及所投入的大量精力和规划。由于此次回收工作的特殊性，必须使用专门的工具和技术进行锁定和回收。
{"title":"Fit-For-Purpose Heavy-Duty Fishing Equipment Designed to Safely Retrieve a Damaged Wireline Cable from an Active, Sour Gas Well Located Offshore","authors":"M. Amri, R. Macaulay, S. Aboelnaga, A. Abouganem, M. Al Dahhan","doi":"10.2118/218350-ms","DOIUrl":"https://doi.org/10.2118/218350-ms","url":null,"abstract":"\u0000 Wireline operations play a crucial role in the oil and gas industry, facilitating essential tasks like well maintenance, data collection, and intervention. These operations involve deploying substantial downhole tools and large cables into the wellbore, but this endeavor is not without its challenges. Particularly, when a wireline cable breaks downhole, it poses significant risks.\u0000 Unplanned wireline breakages result in demanding heavy-duty fishing operations when they occur in challenging offshore environments and unfavorable downhole conditions. In this work, strategic planning and execution were applied in a complex e-line cable recovery in a live, sour gas well without the need for well kill operations. This undertaking necessitated a unique approach to safety and setup, starting with a thorough assessment of the challenging well conditions. A comprehensive fishing plan was then developed to embrace all potential scenarios. The operation involved the use of advanced heavy-duty fishing tools and solutions specifically designed to withstand the well conditions.\u0000 The success of this endeavor is evident in the completion of two recovery operations, all resulting in the successful retrieval of the wire. This first achievement enables customers to restore wellbore access and proceed with their planned interventions. One of these operations involved recovering ~ 4000ft of 5/16in Eline cable and upper section of the fish using mechanical wireline and coiled tubing.\u0000 While SPE-218323-MS (ICOTA A. Abouganem 2024) provides details about the first recovery, this paper aims to present a more comprehensive overview of the second recovery. Specifically, this recovery involved retrieving a 0.350-in Polymer encapsulated wireline cable using a 5/16-in Heavy Duty braided wireline cable within a 7-in. tubing., representing the first occurrence of such a cable recovery on a global scale. The paper delves into the specific techniques employed and the substantial effort and planning invested in successfully recovering this distinctive cable, recognized for its unique shape characterized by elevated breaking strength and rigidity. The distinct nature of this recovery necessitated the utilization of specialized tools and techniques for both latching and recovery.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"36 s155","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394879","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}
C. Torres, S. Livescu, Z. Carlisle, R. Whyte, J. Gatabi, K. Clark, B. Albaalbaki
Coiled tubing has historically been a supporting technology deemed to interact closely with other technologies, given its versatility on equipment, pipe size and configuration, fluids used, tools conveyance, and interaction with the reservoir. Its applicability and value for hydrocarbon production have been vastly documented from drilling and completions to production enhancement and well abandonment. This paper describes a novel application, where an ultra-compact coiled tubing unit (UCCTU) was designed and built for shallow geothermal well drilling and reservoir/aquifer characterization, as part of a project to deliver geothermal energy in dense urban areas across the United States, decarbonizing buildings and reducing their dependance on the electrical grid. The UCCTU was designed and built in six months, where a conventional skid coiled tubing unit was customized for this shallow geothermal drilling application. Considering inner city weight, width, length, and height limitations, two complementing trucks were built. The equipment includes a control cabin, wet kit, coiled tubing reel, 2 3/8-in.coiled tubing with wired downhole telemetry, injector head, stripper, crane, and fluid pump, built considering the smallest footprint possible to ease access in streets and avenues. Engineering was performed to deliver the unit within the required time frame and evaluate modifications needed on the equipment to build this prototype, which would be used to drill wells and log during the process by means of the downhole telemetry. The unit went into field testing, running 2-3/8-in pipe with a downhole motor, drilling bit, and logging tools. At the time of writing this abstract, a total of four wells were drilled, which provided improvement opportunities: Unit design improvementsRig up and rig down process.Drilling and logging operational efficiencies.Location set up and layout.Aquifer characterization Several other details are included regarding shallow geothermal well design for direct heating and cooling applications, and tensile force analysis cases for certain coiled tubing configurations. This coiled tubing unit application is a disruptive step change on how the units can be designed for shallow well drilling, how they can be made more efficient, and most importantly, how can we transition oil & gas (O&G) proven technologies, such as coiled tubing, drilling, and logging, into geothermal energy production.
{"title":"Geothermal Energy: A Novel Coiled Tubing Technology Transition","authors":"C. Torres, S. Livescu, Z. Carlisle, R. Whyte, J. Gatabi, K. Clark, B. Albaalbaki","doi":"10.2118/218288-ms","DOIUrl":"https://doi.org/10.2118/218288-ms","url":null,"abstract":"\u0000 Coiled tubing has historically been a supporting technology deemed to interact closely with other technologies, given its versatility on equipment, pipe size and configuration, fluids used, tools conveyance, and interaction with the reservoir. Its applicability and value for hydrocarbon production have been vastly documented from drilling and completions to production enhancement and well abandonment. This paper describes a novel application, where an ultra-compact coiled tubing unit (UCCTU) was designed and built for shallow geothermal well drilling and reservoir/aquifer characterization, as part of a project to deliver geothermal energy in dense urban areas across the United States, decarbonizing buildings and reducing their dependance on the electrical grid.\u0000 The UCCTU was designed and built in six months, where a conventional skid coiled tubing unit was customized for this shallow geothermal drilling application. Considering inner city weight, width, length, and height limitations, two complementing trucks were built. The equipment includes a control cabin, wet kit, coiled tubing reel, 2 3/8-in.coiled tubing with wired downhole telemetry, injector head, stripper, crane, and fluid pump, built considering the smallest footprint possible to ease access in streets and avenues. Engineering was performed to deliver the unit within the required time frame and evaluate modifications needed on the equipment to build this prototype, which would be used to drill wells and log during the process by means of the downhole telemetry.\u0000 The unit went into field testing, running 2-3/8-in pipe with a downhole motor, drilling bit, and logging tools. At the time of writing this abstract, a total of four wells were drilled, which provided improvement opportunities: Unit design improvementsRig up and rig down process.Drilling and logging operational efficiencies.Location set up and layout.Aquifer characterization\u0000 Several other details are included regarding shallow geothermal well design for direct heating and cooling applications, and tensile force analysis cases for certain coiled tubing configurations.\u0000 This coiled tubing unit application is a disruptive step change on how the units can be designed for shallow well drilling, how they can be made more efficient, and most importantly, how can we transition oil & gas (O&G) proven technologies, such as coiled tubing, drilling, and logging, into geothermal energy production.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"62 S285","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394657","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}
J. Alvarez, Carlos Torres, Juan Corrales, Joshua Travesso, X. Alarcon, Deylla Gomes, Ahmed El-Beltagy, Massimo de Leonardis, Jonnathan Tellez, Miguel Ramirez
Inflatable packers have been the preferred technique for the selective placement of chemical treatments in a wellbore with Coiled Tubing (CT). Traditionally, these have come with some limitations, such as power supply, Real-Time (RT) positioning, surface control, differential pressure activation, ball drop setting, tension, reciprocating set systems, and the ability to quickly change the tool flow path based on treatment response. This paper discusses the first electrically controlled packer implementation that drastically improved operational efficiency in Iraq. This case relates to a mature field in Iraq where precise selective acidization of vuggy carbonate zones with high permeability contrasts was required. The operation was carried out successfully with an electrically controlled packer suitable for acid that provided real-time downhole insight to improve the decision-making process and a precise, flawless acidizing operation. Additionally, the electric actuation system enabled independent control of the flow path position throughout the operation, allowing fluid injection above or below the element to suit the requirements of the operation as needed. The unique solution provided in this paper confirms the benefits of customizing fiber optic and electric technology with an inflatable packer to accurately place the element and selectively stimulate zones with high permeability contrast. A RT downhole sensor module also provides critical information to ensure the operation is carried out as intended. The particular sensors that helped carry out this operation included the Casing Collar Locator (CCL) and Gamma-Ray (GR) to correlate depth, internal and external temperatures, a load module, and internal and external pressure measurements to precisely position the packer in between two layers of a narrow interval without exceeding either the reservoir frac pressure or the packer element differential pressure. This revolutionary technique was successfully implemented on an injection well, saving more than 24 hours of intervention time and allowing early injection to reduce costs for the customer. The CT Electric Inflatable Packer (EIP) enabled the splitting of the operation into two treatments, above and below the packer, during the same run. The approach to this intervention increased operational efficiency while reducing waste to optimize the overall well intervention cost with RT data. This paper describes how a new versatile EIP technology can improve operational efficiency and reduce non-productive time on various applications, such as selective treatments, multiple selective acidizing of sleeves, clusters, intervals, water shut off with sealant fluids, or chemical sand consolation with resins.
{"title":"World's First Coiled Tubing Electric Inflatable Packer Deployment of a Fully Hybrid Optical/Electrical Activated Multi-Set Inflatable Element for Selective Acidizing. A Case Study from Iraq","authors":"J. Alvarez, Carlos Torres, Juan Corrales, Joshua Travesso, X. Alarcon, Deylla Gomes, Ahmed El-Beltagy, Massimo de Leonardis, Jonnathan Tellez, Miguel Ramirez","doi":"10.2118/218295-ms","DOIUrl":"https://doi.org/10.2118/218295-ms","url":null,"abstract":"\u0000 Inflatable packers have been the preferred technique for the selective placement of chemical treatments in a wellbore with Coiled Tubing (CT). Traditionally, these have come with some limitations, such as power supply, Real-Time (RT) positioning, surface control, differential pressure activation, ball drop setting, tension, reciprocating set systems, and the ability to quickly change the tool flow path based on treatment response. This paper discusses the first electrically controlled packer implementation that drastically improved operational efficiency in Iraq.\u0000 This case relates to a mature field in Iraq where precise selective acidization of vuggy carbonate zones with high permeability contrasts was required. The operation was carried out successfully with an electrically controlled packer suitable for acid that provided real-time downhole insight to improve the decision-making process and a precise, flawless acidizing operation. Additionally, the electric actuation system enabled independent control of the flow path position throughout the operation, allowing fluid injection above or below the element to suit the requirements of the operation as needed.\u0000 The unique solution provided in this paper confirms the benefits of customizing fiber optic and electric technology with an inflatable packer to accurately place the element and selectively stimulate zones with high permeability contrast. A RT downhole sensor module also provides critical information to ensure the operation is carried out as intended. The particular sensors that helped carry out this operation included the Casing Collar Locator (CCL) and Gamma-Ray (GR) to correlate depth, internal and external temperatures, a load module, and internal and external pressure measurements to precisely position the packer in between two layers of a narrow interval without exceeding either the reservoir frac pressure or the packer element differential pressure.\u0000 This revolutionary technique was successfully implemented on an injection well, saving more than 24 hours of intervention time and allowing early injection to reduce costs for the customer. The CT Electric Inflatable Packer (EIP) enabled the splitting of the operation into two treatments, above and below the packer, during the same run. The approach to this intervention increased operational efficiency while reducing waste to optimize the overall well intervention cost with RT data.\u0000 This paper describes how a new versatile EIP technology can improve operational efficiency and reduce non-productive time on various applications, such as selective treatments, multiple selective acidizing of sleeves, clusters, intervals, water shut off with sealant fluids, or chemical sand consolation with resins.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"113 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394949","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}
Emin Jafarov, Yoliandri Susilo, Farid Agayev, Aydan Mikayilova, Nadir Gafarov, Imran Guliyev, Matin Allahverdiyev, Ilkin Guliyev, T. Sadigov, Zahid Hasanov, Ahad Pashayev, Turan Eyyubbayli
The Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The major reservoir zones are comprised of poorly sorted and weakly consolidated multi-layer sandstone formations. While Open-hole Gravel Pack (OHGP) completions have become the standard design for production wells, there are also several Cased & Perforated (C&P) wells from early field development along with some opportunistic Up-hole Re-completion (UHRC) C&P wells that were converted from OHGP. As the field matures with increasing depletion, water cut and gas/oil ratio (GOR), OHGP wells with vulnerability in the pack (incomplete pack) and C&P wells start to produce sand. Consequently, those wells are choked back resulting in sand-induced production deferral. Several sand control remedial work technologies were evaluated for the field and ceramic screen technology was chosen due to higher erosion resistance to cope with high flow rates and GOR in ACG wells. Three thru-tubing sand control remedial works using ceramic screen has been trialed successfully, both inside C&P well and high angle OHGP wells with unpacked section at the toe which previously isolated by bridge plug. The ceramic screen bottom-hole assembly (BHA) was deployed using coiled tubing with total BHA string length up to 178m. A snap type connector was used to minimize number of runs into each well, by allowing running string of multiple sections of ceramic screen and blank pipe in one trip. The ceramic screen installation inside C&P well demonstrated higher post-job skin compared to OHGP application, however having ceramic screen in the well allowed to produce with 3x higher drawdown at higher water cut up to ~40% with limited sand production and extend the well life considering typical C&P well failed with much smaller water cut. The ceramic screen installed in OHGP screen across unpacked section shows minimal skin change. In average there was ~2,500 bbls/day immediate incremental oil gain after each sand remediation work. This successful result demonstrates the viability of this remedial works to unlock production potential of producer wells and reduce sand-induced production deferrals in the field. This paper primarily discusses design, execution, result and learning from the first three thru-tubing sand control remedial work that was done in the ACG field.
{"title":"First Three Thru-Tubing Sand Control Remedial Works Using Ceramic Screen in ACG Field: Design, Execution, Evaluation and Strategy for Next Jobs","authors":"Emin Jafarov, Yoliandri Susilo, Farid Agayev, Aydan Mikayilova, Nadir Gafarov, Imran Guliyev, Matin Allahverdiyev, Ilkin Guliyev, T. Sadigov, Zahid Hasanov, Ahad Pashayev, Turan Eyyubbayli","doi":"10.2118/218341-ms","DOIUrl":"https://doi.org/10.2118/218341-ms","url":null,"abstract":"\u0000 The Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The major reservoir zones are comprised of poorly sorted and weakly consolidated multi-layer sandstone formations. While Open-hole Gravel Pack (OHGP) completions have become the standard design for production wells, there are also several Cased & Perforated (C&P) wells from early field development along with some opportunistic Up-hole Re-completion (UHRC) C&P wells that were converted from OHGP. As the field matures with increasing depletion, water cut and gas/oil ratio (GOR), OHGP wells with vulnerability in the pack (incomplete pack) and C&P wells start to produce sand. Consequently, those wells are choked back resulting in sand-induced production deferral.\u0000 Several sand control remedial work technologies were evaluated for the field and ceramic screen technology was chosen due to higher erosion resistance to cope with high flow rates and GOR in ACG wells. Three thru-tubing sand control remedial works using ceramic screen has been trialed successfully, both inside C&P well and high angle OHGP wells with unpacked section at the toe which previously isolated by bridge plug. The ceramic screen bottom-hole assembly (BHA) was deployed using coiled tubing with total BHA string length up to 178m. A snap type connector was used to minimize number of runs into each well, by allowing running string of multiple sections of ceramic screen and blank pipe in one trip.\u0000 The ceramic screen installation inside C&P well demonstrated higher post-job skin compared to OHGP application, however having ceramic screen in the well allowed to produce with 3x higher drawdown at higher water cut up to ~40% with limited sand production and extend the well life considering typical C&P well failed with much smaller water cut. The ceramic screen installed in OHGP screen across unpacked section shows minimal skin change. In average there was ~2,500 bbls/day immediate incremental oil gain after each sand remediation work. This successful result demonstrates the viability of this remedial works to unlock production potential of producer wells and reduce sand-induced production deferrals in the field.\u0000 This paper primarily discusses design, execution, result and learning from the first three thru-tubing sand control remedial work that was done in the ACG field.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"34 S127","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395078","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}
In today's oil and gas landscape, production recovery from existing wells remains a pertinent challenge. The ever-increasing demand for hydrocarbons and the emphasis on optimized output have led to the endeavor of maximizing production from established wells. However, despite technological advancements, a significant proportion of these wells underperform, either due to inherent issues, such as formation damage, or a decline in reservoir pressure over time. Traditional methods like bullheading chemicals from the surface have struggled to consistently deliver efficient and sustained solutions. This pressing issue has prompted a shift toward innovative methodologies to restore and sustain productivity in underperforming wells. The oil and gas industry requires robust and sustainable techniques that can efficiently address these challenges, optimizing the productivity of existing wells. This paper presents a novel, data-driven process that uses a downhole, hydraulically activated system to restore and sustain productivity of sub-par producing oil and gas wells. The paper details the steps required to identify and restore the productivity of underperforming wells. Results are compared with traditional solutions based on bull heading chemical treatments from surface.
{"title":"How to Sustainably Improve Production Recovery from Existing Wells","authors":"E. Moen, R. Antonsen, E. A. Ejofodomi","doi":"10.2118/218315-ms","DOIUrl":"https://doi.org/10.2118/218315-ms","url":null,"abstract":"\u0000 In today's oil and gas landscape, production recovery from existing wells remains a pertinent challenge. The ever-increasing demand for hydrocarbons and the emphasis on optimized output have led to the endeavor of maximizing production from established wells. However, despite technological advancements, a significant proportion of these wells underperform, either due to inherent issues, such as formation damage, or a decline in reservoir pressure over time. Traditional methods like bullheading chemicals from the surface have struggled to consistently deliver efficient and sustained solutions. This pressing issue has prompted a shift toward innovative methodologies to restore and sustain productivity in underperforming wells. The oil and gas industry requires robust and sustainable techniques that can efficiently address these challenges, optimizing the productivity of existing wells.\u0000 This paper presents a novel, data-driven process that uses a downhole, hydraulically activated system to restore and sustain productivity of sub-par producing oil and gas wells. The paper details the steps required to identify and restore the productivity of underperforming wells. Results are compared with traditional solutions based on bull heading chemical treatments from surface.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"113 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395126","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a comprehensive methodology for developing an artificial intelligence (AI) model to synthesize downhole measurements as a digital backup for measurement while drilling (MWD) sensors, ensuring uninterrupted drilling in coiled tubing drilling operations (CTD). The MWD tool plays a pivotal role in CTD, acquiring critical measurements for safe drilling operations. These measurements are critical for decision-making, monitoring, and managing the drilling process. One significant challenge faced during CTD is the occurrence of sensor failures in MWD tools, which hinders the real-time assessment of downhole conditions. Such failures can lead to operational downtime due to the need to trip out the bottomhole assembly (BHA) for sensor replacement. To address this issue, an AI based model using synthesized downhole measurements as backup for MWD tools has been developed for CTD. The proposed AI model leverages custom regression models for each MWD sensor, using various machine learning techniques such as Random Forest, Gradient Boosted Trees, and more to predict sensor values when a sensor fails. The model is continuously updated with new data and uses predefined thresholds and AI-based models to detect sensor failures and assess the uncertainty of predictions. To evaluate the model's effectiveness, various machine learning models are compared using metrics such as mean absolute error (MAE), and r-squared score (R2). The results indicate high accuracy in predicting sensor data, even in the absence of failed sensors, for annulus pressure, pipe pressure, and weight on bit (WOB). This approach could reduce nonproductive time (NPT) and costs associated with sensor failures in CTD operations. It provides a robust framework for using AI to maintain uninterrupted drilling operations by synthesizing sensor data when needed, ensuring the seamless execution of drilling operations.
{"title":"An Artificial Intelligence Model to Synthesize Measurements While Drilling Sensors for Coiled Tubing Drilling","authors":"C. Urdaneta, C. Jeong, A. Zheng","doi":"10.2118/218351-ms","DOIUrl":"https://doi.org/10.2118/218351-ms","url":null,"abstract":"\u0000 This paper presents a comprehensive methodology for developing an artificial intelligence (AI) model to synthesize downhole measurements as a digital backup for measurement while drilling (MWD) sensors, ensuring uninterrupted drilling in coiled tubing drilling operations (CTD). The MWD tool plays a pivotal role in CTD, acquiring critical measurements for safe drilling operations. These measurements are critical for decision-making, monitoring, and managing the drilling process. One significant challenge faced during CTD is the occurrence of sensor failures in MWD tools, which hinders the real-time assessment of downhole conditions. Such failures can lead to operational downtime due to the need to trip out the bottomhole assembly (BHA) for sensor replacement. To address this issue, an AI based model using synthesized downhole measurements as backup for MWD tools has been developed for CTD. The proposed AI model leverages custom regression models for each MWD sensor, using various machine learning techniques such as Random Forest, Gradient Boosted Trees, and more to predict sensor values when a sensor fails. The model is continuously updated with new data and uses predefined thresholds and AI-based models to detect sensor failures and assess the uncertainty of predictions. To evaluate the model's effectiveness, various machine learning models are compared using metrics such as mean absolute error (MAE), and r-squared score (R2). The results indicate high accuracy in predicting sensor data, even in the absence of failed sensors, for annulus pressure, pipe pressure, and weight on bit (WOB). This approach could reduce nonproductive time (NPT) and costs associated with sensor failures in CTD operations. It provides a robust framework for using AI to maintain uninterrupted drilling operations by synthesizing sensor data when needed, ensuring the seamless execution of drilling operations.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"52 S263","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394483","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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