Mubashir Mubashir Ahmad, Ayman El Shahat, M. O. El-Meguid, Ali Sulaiman Bin Sumaida, Hessa Mohammed Al Shehhi, Fawad Zain Yousfi, M. Albadi, Ibrahim Al Mansouri, T. Solaiman, M. Baslaib, S. Alhouqani, Mariam M. Al Reyami, A. Gadelhak, A. Shaker, A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, S. Alsenaidi, Bakheeta Al Muhairi, E. Al Mheiri, Omar Al Jeelani, Noora Al Maria, Mahmoud A Basioni, S. Sayed, Ahmed Yahya Al Blooshi, Ahmed Mahmoud Elmahdi, Ali Al Mansoori, Jasim Ali Alloghani
Deepest Deviated Appraisal well in Upper Khuff reservoir in a small artificial island, located about 100 KM away from Abu Dhabi shore was successfully drilled and tested. The well has been recognized as the deepest deviated well on offshore Island with highest bottom hole reservoir temperature in UAE about 375 deg F (190 degrees C) and exceeding 9000 psi reservoir pressure complemented with impurities of H2S ranging from 10-22% and CO2 between 9-20%. The challenges were immense, from designing to execution, including securing special materials for the unique well design to accommodate the sour environment of Khuff reservoir as exploring new reservoirs always counter many risks comparing to developed reservoirs. The execution was driven with the focus of maximizing the ultimate value and benefit for ADNOC, our respected partners, the community and the UAE. The field is located in the most sensitive and ecological important area and is under UNESCO Biosphere reserve. The appraisal well was successfully drilled to Khuff reservoir at a depth of 19000 ft. The well test using Drill stem test (DST string) was conducted. Multiple challenges ranging from HSE, material selection, drilling and logging tools availability, limitations and procuring them in time were overcome by utilizing the World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas. Another major challenge faced during the drilling deeper reservoir was mud rheology changes due to high temperatures. The logging program was tailored to overcome the challenges posed by the mud, high temperature, high pressure, sour condition and to gain maximum representative reservoir data in a reservoir where high-pressure steaks and geological unconformities were anticipated. The Drill stem test, (DST) string was successfully POOH after acquiring all the objectives from Khuff K-4 testing under above mentioned harsh environment. The zonal isolation was carried out with cement and rig was released. The drilling and testing operation was conducted with high level of cooperation and excellence accomplishing the well set objectives without (Lost Time Injury). Lessons learned are widely shared with all the teams across the region to expedite and improve on the technologies used for sour gas production. ADNOC Onshore demonstrated 100% HSE, full commitment, high collaboration and efficient outcome ensuring safety compliance for the successful delivery of this highly critical project. This paper presents the various challenges faced and overcome while carrying out the Drilling and testing of the HPHT Sour well offshore.
{"title":"Deepest Deviated HPHT Gas Well Drilling and Testing Challenges in an Offshore Island Case-study","authors":"Mubashir Mubashir Ahmad, Ayman El Shahat, M. O. El-Meguid, Ali Sulaiman Bin Sumaida, Hessa Mohammed Al Shehhi, Fawad Zain Yousfi, M. Albadi, Ibrahim Al Mansouri, T. Solaiman, M. Baslaib, S. Alhouqani, Mariam M. Al Reyami, A. Gadelhak, A. Shaker, A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, S. Alsenaidi, Bakheeta Al Muhairi, E. Al Mheiri, Omar Al Jeelani, Noora Al Maria, Mahmoud A Basioni, S. Sayed, Ahmed Yahya Al Blooshi, Ahmed Mahmoud Elmahdi, Ali Al Mansoori, Jasim Ali Alloghani","doi":"10.2118/207506-ms","DOIUrl":"https://doi.org/10.2118/207506-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Deepest Deviated Appraisal well in Upper Khuff reservoir in a small artificial island, located about 100 KM away from Abu Dhabi shore was successfully drilled and tested.\u0000 The well has been recognized as the deepest deviated well on offshore Island with highest bottom hole reservoir temperature in UAE about 375 deg F (190 degrees C) and exceeding 9000 psi reservoir pressure complemented with impurities of H2S ranging from 10-22% and CO2 between 9-20%.\u0000 \u0000 \u0000 \u0000 The challenges were immense, from designing to execution, including securing special materials for the unique well design to accommodate the sour environment of Khuff reservoir as exploring new reservoirs always counter many risks comparing to developed reservoirs.\u0000 The execution was driven with the focus of maximizing the ultimate value and benefit for ADNOC, our respected partners, the community and the UAE. The field is located in the most sensitive and ecological important area and is under UNESCO Biosphere reserve.\u0000 \u0000 \u0000 \u0000 The appraisal well was successfully drilled to Khuff reservoir at a depth of 19000 ft. The well test using Drill stem test (DST string) was conducted.\u0000 Multiple challenges ranging from HSE, material selection, drilling and logging tools availability, limitations and procuring them in time were overcome by utilizing the World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas.\u0000 Another major challenge faced during the drilling deeper reservoir was mud rheology changes due to high temperatures. The logging program was tailored to overcome the challenges posed by the mud, high temperature, high pressure, sour condition and to gain maximum representative reservoir data in a reservoir where high-pressure steaks and geological unconformities were anticipated.\u0000 The Drill stem test, (DST) string was successfully POOH after acquiring all the objectives from Khuff K-4 testing under above mentioned harsh environment. The zonal isolation was carried out with cement and rig was released.\u0000 \u0000 \u0000 \u0000 The drilling and testing operation was conducted with high level of cooperation and excellence accomplishing the well set objectives without (Lost Time Injury).\u0000 Lessons learned are widely shared with all the teams across the region to expedite and improve on the technologies used for sour gas production. ADNOC Onshore demonstrated 100% HSE, full commitment, high collaboration and efficient outcome ensuring safety compliance for the successful delivery of this highly critical project.\u0000 This paper presents the various challenges faced and overcome while carrying out the Drilling and testing of the HPHT Sour well offshore.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87528340","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}
Erismar Rubio, M. Y. Alklih, N. Reddicharla, Abobaker Albelazi, Melike Dilsiz, Mohamed Ali Al-Attar, R. Davila, K. Khan
Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators. The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects. These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly. Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact. In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.
{"title":"Integrated Automation and Data-Driven Workflow for CO2 Project Management – Case Study from a Smart Oil Field in the Middle-East","authors":"Erismar Rubio, M. Y. Alklih, N. Reddicharla, Abobaker Albelazi, Melike Dilsiz, Mohamed Ali Al-Attar, R. Davila, K. Khan","doi":"10.2118/207422-ms","DOIUrl":"https://doi.org/10.2118/207422-ms","url":null,"abstract":"\u0000 Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators.\u0000 The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects.\u0000 These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly.\u0000 Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact.\u0000 In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84442149","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination. Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification. Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas. One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation. This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence. Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario. This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.
{"title":"Enhancing Gas Injection Compressors Performance by Lateral Thinking Resulting in 0.62 Million Barrels Oil Per Year Additional Production Capacity at Zero Cost","authors":"M. Arif, Abdulla Mohammed Al Jneibi","doi":"10.2118/208186-ms","DOIUrl":"https://doi.org/10.2118/208186-ms","url":null,"abstract":"\u0000 The Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination.\u0000 Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification.\u0000 Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas.\u0000 One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation.\u0000 This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence.\u0000 Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario.\u0000 This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88232512","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. Jaya, Abdrahman Sharif, Ali Ahmed Reda Abdulkarim, Ghazali Ahmad Riza, Maleki Ali Hajian, Elsebakhi Emad
The performance of ML-based rock properties prediction from seismic with limited and sparse well data is very often inadequate. To address this limitation, we propose a novel automatic well log regularization (ALR) method with specially designed feature augmentation strategy to improve the prediction accuracy. The effectiveness of ALR method is showcased on field data in Malay basin where we successfully predict elastic logs with 30% higher accuracy, while using only 28% less training dataset. The ALR workflow (Figure 1): (1) feature selection and augmentation; (2) training and prediction and (3) prediction optimizations. The workflow starts with predicting any logs type which are available at training but not in blind wells using standard ML workflow for all blind wells (Step 1-2). Then, these intermediately predicted logs at blind well were jointly used as input features together with seismic-derived attributes using a specially designed feature augmentation strategy (Step 3). Finally, Step 1and 2 are then repeated to predict the elastic logs using these augmented input features. The ALR method was applied on an oil/gas field data in Malay basin to predict elastic logs (AI and SI) at five blind wells from seismic data only and compared to the standard ML workflow. Two wells were used as training (28% of all data). The prediction performance of standard ML workflow (Figure 2a) is poor and can only capture general mean values of the actual AI/SI logs. The results of ALR workflow (Figure 2b) shows 30% better prediction performance compared to the standard ML workflow. In general, the background and high-resolution trend are well captured, and the overall prediction performance is improved using the new proposed prediction method. There are conceivably two explanations for this result: a) the background (low frequency) trend of the well log is properly reconstructed in ALR using only using seismic data. This could mainly lie in the ability of augmented features in better learning the uncertain reflection-reception relationship between seismic data and elastic logs, as well as the spatial/time-varying property of seismic data; (b) The ability to learn meaningful nonlinear feature relationship between input (feature) and output (label) variables with little or no supervision seems to work properly using specially designed feature augmentation. The ALR method is an ML-based pseudo log generation from seismic data using specially designed feature augmentation strategy. The novel ALR implementation relaxes the requirement of having a massive amount of high-quality labeled data for training and can therefore be applied in areas with limited well data information. ALR method is proven to be highly accurate for direct elastic logs prediction and can potentially be extended to estimate petrophysical properties from seismic data.
{"title":"Accurate Pseudo Log Prediction Using Machine Learning Based Automatic Log Regularization and Feature Augmentation Method","authors":"M. Jaya, Abdrahman Sharif, Ali Ahmed Reda Abdulkarim, Ghazali Ahmad Riza, Maleki Ali Hajian, Elsebakhi Emad","doi":"10.2118/207230-ms","DOIUrl":"https://doi.org/10.2118/207230-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The performance of ML-based rock properties prediction from seismic with limited and sparse well data is very often inadequate. To address this limitation, we propose a novel automatic well log regularization (ALR) method with specially designed feature augmentation strategy to improve the prediction accuracy. The effectiveness of ALR method is showcased on field data in Malay basin where we successfully predict elastic logs with 30% higher accuracy, while using only 28% less training dataset.\u0000 \u0000 \u0000 \u0000 The ALR workflow (Figure 1): (1) feature selection and augmentation; (2) training and prediction and (3) prediction optimizations. The workflow starts with predicting any logs type which are available at training but not in blind wells using standard ML workflow for all blind wells (Step 1-2). Then, these intermediately predicted logs at blind well were jointly used as input features together with seismic-derived attributes using a specially designed feature augmentation strategy (Step 3). Finally, Step 1and 2 are then repeated to predict the elastic logs using these augmented input features.\u0000 \u0000 \u0000 \u0000 The ALR method was applied on an oil/gas field data in Malay basin to predict elastic logs (AI and SI) at five blind wells from seismic data only and compared to the standard ML workflow. Two wells were used as training (28% of all data). The prediction performance of standard ML workflow (Figure 2a) is poor and can only capture general mean values of the actual AI/SI logs. The results of ALR workflow (Figure 2b) shows 30% better prediction performance compared to the standard ML workflow. In general, the background and high-resolution trend are well captured, and the overall prediction performance is improved using the new proposed prediction method. There are conceivably two explanations for this result: a) the background (low frequency) trend of the well log is properly reconstructed in ALR using only using seismic data. This could mainly lie in the ability of augmented features in better learning the uncertain reflection-reception relationship between seismic data and elastic logs, as well as the spatial/time-varying property of seismic data; (b) The ability to learn meaningful nonlinear feature relationship between input (feature) and output (label) variables with little or no supervision seems to work properly using specially designed feature augmentation.\u0000 \u0000 \u0000 \u0000 The ALR method is an ML-based pseudo log generation from seismic data using specially designed feature augmentation strategy. The novel ALR implementation relaxes the requirement of having a massive amount of high-quality labeled data for training and can therefore be applied in areas with limited well data information. ALR method is proven to be highly accurate for direct elastic logs prediction and can potentially be extended to estimate petrophysical properties from seismic data.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86930624","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Lowdon, Hiep Tien Nguyen, Mahmoud Elgizawy, Saback Victor
Wellbore surveying is a critical component of any well construction project. Understanding the position of a well in 3D space allows for the wells geological objectives to be carried out while safely avoiding other wellbores. Wellbore surveys are generally conducted using a magnetically referenced measurement while drilling tool (MWD) and taken while static, either before, after or sometimes during the connection. The drillstring is often worked to release trapped torque and time is often taken waiting for the survey to be pumped up. All of this consumes rig time and opens the wellbore up to wellbore instability issues. The application of definitive dynamic surveys (DDS) which are static MWD quality surveys taken while drilling and updated continuously. There is no longer a need to stop and take a static survey eliminating MWD surveying related rig time, reducing drilling risks from additional pumps off time and improving TVD accuracy and directional control. The rig time taken for surveying with and without DDS will be compared between similar wells in the field, and detailed analysis of relative tortuosity between DDS and non-DDS wells will also be conducted. Trajectory control analysis will be reviewed by looking at the difference in the number of downlinks between DDS and no DDS wells and also the deviation from the planned trajectory. An overall analysis of on bottom ROP will be made and an analysis as to the relative differences in TVD between static and DDS survey will be carried out. This abstract will outline the rig time and operational savings from DDS, it will detail the surveying time savings, directional control improvements, TVD placement differences to static surveys and provide costs savings as a comparison to previous similar wells. This will be outlined over a number of wells, divided by sections as the wells are batch drilled and provide an insight into the benefits of DDS on a drilling campaign. Some discussion will be made as to the efficacy of the DDS surveys and how their error model has been developed. DDS is a unique and novel way of taking surveys while drilling, providing static MWD quality without the added rig time costs but at a much higher frequency that the typical once a stand survey program. This paper outlines the cost and process savings associated with using the DDS surveys.
{"title":"Definitive Dynamic MWD Surveys Generate Rig Time Savings and Flat Time Reductions in the Middle East","authors":"R. Lowdon, Hiep Tien Nguyen, Mahmoud Elgizawy, Saback Victor","doi":"10.2118/207301-ms","DOIUrl":"https://doi.org/10.2118/207301-ms","url":null,"abstract":"\u0000 Wellbore surveying is a critical component of any well construction project. Understanding the position of a well in 3D space allows for the wells geological objectives to be carried out while safely avoiding other wellbores.\u0000 Wellbore surveys are generally conducted using a magnetically referenced measurement while drilling tool (MWD) and taken while static, either before, after or sometimes during the connection. The drillstring is often worked to release trapped torque and time is often taken waiting for the survey to be pumped up. All of this consumes rig time and opens the wellbore up to wellbore instability issues.\u0000 The application of definitive dynamic surveys (DDS) which are static MWD quality surveys taken while drilling and updated continuously. There is no longer a need to stop and take a static survey eliminating MWD surveying related rig time, reducing drilling risks from additional pumps off time and improving TVD accuracy and directional control.\u0000 The rig time taken for surveying with and without DDS will be compared between similar wells in the field, and detailed analysis of relative tortuosity between DDS and non-DDS wells will also be conducted. Trajectory control analysis will be reviewed by looking at the difference in the number of downlinks between DDS and no DDS wells and also the deviation from the planned trajectory. An overall analysis of on bottom ROP will be made and an analysis as to the relative differences in TVD between static and DDS survey will be carried out.\u0000 This abstract will outline the rig time and operational savings from DDS, it will detail the surveying time savings, directional control improvements, TVD placement differences to static surveys and provide costs savings as a comparison to previous similar wells. This will be outlined over a number of wells, divided by sections as the wells are batch drilled and provide an insight into the benefits of DDS on a drilling campaign. Some discussion will be made as to the efficacy of the DDS surveys and how their error model has been developed.\u0000 DDS is a unique and novel way of taking surveys while drilling, providing static MWD quality without the added rig time costs but at a much higher frequency that the typical once a stand survey program. This paper outlines the cost and process savings associated with using the DDS surveys.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87425513","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}
Yogi Adi Guna, Michael A. Frank, Novianto Rochman, Thomas Herdian Abi Putra, M. Irvan, Alfatah Fitriansyah, Ibnu Kurniawan
An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well. To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength. The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed. The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.
{"title":"Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia","authors":"Yogi Adi Guna, Michael A. Frank, Novianto Rochman, Thomas Herdian Abi Putra, M. Irvan, Alfatah Fitriansyah, Ibnu Kurniawan","doi":"10.2118/207419-ms","DOIUrl":"https://doi.org/10.2118/207419-ms","url":null,"abstract":"\u0000 An operator recorded 1100 psi of sustained casing pressure between a 9-5/8\" casing and a 3.5\" production tubing annulus seven days after the cementing operation was completed for the 3.5\" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8\" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5\" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well.\u0000 To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength.\u0000 The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed.\u0000 The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82489133","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Gadelhak, Mohamed Al-Badi, Ahmed Al-Bairaq, E. Al Mheiri, Abdullah Haj Al-Hosani, Z. Ahmed, Sami Ullah Bashir Ahmed, Mubashir Ahmed, Waleed Omar Abedelkhalik, Sameh Hassan Naser, Haysam El-Shater, Wessam Al Assar, Steve Ross, Blair Duncan
The Increase of inactive wells due to subsurface integrity issue is observed in brown fields, Fig-1 is, showing the record for onshore UAE asset, the economic challenges is calling for alternative solutions to restore well integrity with lower cost. Straddle packer application is consists of two tandom packers with spacer pipe in between with anchoring system deployed riglessly in the well to isolate the communication point between Ann A and Tubing.Fig-2, Communication between tubing and annulus A (Failure of primary barrier) is identified as the right candidate wells for straddle packer application, First step is to clearly identify the point of communication, it has been done by annulus pressure investigation excersize during flowing and shut in condition, observing the return of annulus fluid which was the same produced gas Noise log has been conducted and clearly identified the communication point at SPM (Side Pocket Mandrel) to be used for emergency killing, Tubing integrity test was conducted using nippless plugs and inflow test below and above the leak point and confirm no other leak points within the tubing Engineering drawing for the leaking assembly was reviewed to design the dimension of straddle packer assembly, length and packer size It is recommended to deploy the assembly using electric line correlation for accurate depth selection After setting annulus pressure observed no build up Well opened safely to production Leak point arrested, well primary barrier restored Removed from DWS (drilling and workover schedule) and restore well production in addition to improving inactive string KPI for Gas asset Save almost work over cost for gas well XX-197 The way forward is to check the scalability of extending this application among other ADNOC assets and to screen the right candidate wells for this application To add this application as a part of well integrity procedures and recommendations for such like cases
{"title":"Lead Application to Cure Sap Wells by Deploying Straddle Packer, Success Story","authors":"A. Gadelhak, Mohamed Al-Badi, Ahmed Al-Bairaq, E. Al Mheiri, Abdullah Haj Al-Hosani, Z. Ahmed, Sami Ullah Bashir Ahmed, Mubashir Ahmed, Waleed Omar Abedelkhalik, Sameh Hassan Naser, Haysam El-Shater, Wessam Al Assar, Steve Ross, Blair Duncan","doi":"10.2118/207840-ms","DOIUrl":"https://doi.org/10.2118/207840-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The Increase of inactive wells due to subsurface integrity issue is observed in brown fields, Fig-1 is, showing the record for onshore UAE asset, the economic challenges is calling for alternative solutions to restore well integrity with lower cost.\u0000 Straddle packer application is consists of two tandom packers with spacer pipe in between with anchoring system deployed riglessly in the well to isolate the communication point between Ann A and Tubing.Fig-2,\u0000 \u0000 \u0000 \u0000 Communication between tubing and annulus A (Failure of primary barrier) is identified as the right candidate wells for straddle packer application,\u0000 First step is to clearly identify the point of communication, it has been done by annulus pressure investigation excersize during flowing and shut in condition, observing the return of annulus fluid which was the same produced gas\u0000 Noise log has been conducted and clearly identified the communication point at SPM (Side Pocket Mandrel) to be used for emergency killing,\u0000 Tubing integrity test was conducted using nippless plugs and inflow test below and above the leak point and confirm no other leak points within the tubing\u0000 Engineering drawing for the leaking assembly was reviewed to design the dimension of straddle packer assembly, length and packer size\u0000 It is recommended to deploy the assembly using electric line correlation for accurate depth selection\u0000 After setting annulus pressure observed no build up\u0000 Well opened safely to production\u0000 \u0000 \u0000 \u0000 Leak point arrested, well primary barrier restored\u0000 Removed from DWS (drilling and workover schedule) and restore well production in addition to improving inactive string KPI for Gas asset\u0000 Save almost work over cost for gas well XX-197\u0000 \u0000 \u0000 \u0000 The way forward is to check the scalability of extending this application among other ADNOC assets and to screen the right candidate wells for this application\u0000 To add this application as a part of well integrity procedures and recommendations for such like cases\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84969654","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}
D. Speranza, Andrea Vignali, A. Pacini, G. Ori, A. Palucci
Companies that work in the decommissioning of platforms need tools to make smarter and informed business decisions, manage and analyse business data, increase the security of workers and operate under strict environmental protection regulations. INSURE aims at assessing the feasibility of a new service to support the decommissioning of offshore installations by means of technological innovation made available throughout each process’ step. In order to accomplish this, the project gathers high-impact Italian companies bringing together the best applicable technological and scientific know-how. INSURE foresees to combine these know-hows and create a novel tool at the service of the industry to promote a better and safer approach to the operations. Targets of the INSURE project are improving workers’ safety, enhancing environmental monitorings, increasing operations’ efficiency, reducing operational costs, offering a route for future sustainability. Project targets can be achieved through the realisation of an augmented virtual reality platform (AVRP) that will be operated in support of the decommissioning process where the data acquired/transmitted by a plurality of sensors will converge. A fleet control tool integrates information from sensors installed on autonomous aerial and underwater vehicles making use of the Global Satellite Navigation Systems (GSNS) and Satellite Communications (SatCom). The convergence of top-notch technologies (augmented/virtual reality, 3D, robotics, sensors, 5G and Satellite services), together with a cloud of infrastructure, enables a fast and complete access to real-time data at very high resolution. The proposal aims to bring the actual data and information access from the Internet of Things to the Internet of Knowledge paradigm. Confrontation with national and international possible end-users produced a set of user requirements guiding the design of a feasibility study for the realisation of one specific product. The study also includes the evaluation of economic, non-economic viability and possible regulatory constraints to its realisation. The INSURE feasibility study creates the intellectual background for the further step of the process: the realisation and development of a pilot project tailored for the purpose. This combined use of novel technologies represents an innovative integrated approach applied to the management of offshore structures undergoing decommissioning or reconfiguration for other purposes. In addition, it also involves the promotion of sustainable opportunities for commercial, social and educational exploitation of areas and assets (including, for example, the ambit of eco-tourism, renewable energies, carbon capture and storage).
{"title":"Supporting Decommissioning/Conversion of Offshore Structures Applying Innovative Technological Solution INSURE project","authors":"D. Speranza, Andrea Vignali, A. Pacini, G. Ori, A. Palucci","doi":"10.2118/207225-ms","DOIUrl":"https://doi.org/10.2118/207225-ms","url":null,"abstract":"\u0000 Companies that work in the decommissioning of platforms need tools to make smarter and informed business decisions, manage and analyse business data, increase the security of workers and operate under strict environmental protection regulations. INSURE aims at assessing the feasibility of a new service to support the decommissioning of offshore installations by means of technological innovation made available throughout each process’ step.\u0000 In order to accomplish this, the project gathers high-impact Italian companies bringing together the best applicable technological and scientific know-how. INSURE foresees to combine these know-hows and create a novel tool at the service of the industry to promote a better and safer approach to the operations. Targets of the INSURE project are improving workers’ safety, enhancing environmental monitorings, increasing operations’ efficiency, reducing operational costs, offering a route for future sustainability.\u0000 Project targets can be achieved through the realisation of an augmented virtual reality platform (AVRP) that will be operated in support of the decommissioning process where the data acquired/transmitted by a plurality of sensors will converge. A fleet control tool integrates information from sensors installed on autonomous aerial and underwater vehicles making use of the Global Satellite Navigation Systems (GSNS) and Satellite Communications (SatCom). The convergence of top-notch technologies (augmented/virtual reality, 3D, robotics, sensors, 5G and Satellite services), together with a cloud of infrastructure, enables a fast and complete access to real-time data at very high resolution. The proposal aims to bring the actual data and information access from the Internet of Things to the Internet of Knowledge paradigm.\u0000 Confrontation with national and international possible end-users produced a set of user requirements guiding the design of a feasibility study for the realisation of one specific product. The study also includes the evaluation of economic, non-economic viability and possible regulatory constraints to its realisation. The INSURE feasibility study creates the intellectual background for the further step of the process: the realisation and development of a pilot project tailored for the purpose.\u0000 This combined use of novel technologies represents an innovative integrated approach applied to the management of offshore structures undergoing decommissioning or reconfiguration for other purposes. In addition, it also involves the promotion of sustainable opportunities for commercial, social and educational exploitation of areas and assets (including, for example, the ambit of eco-tourism, renewable energies, carbon capture and storage).","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91253984","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}
Gaojing Cao, Xiangzen Wang, Lei Nie, Yaoqiang Hu, Yundong Xie, Gayatri P. Kartoatmodjo, Paul Williams, R. Henson, M. Zhu, Andrew Fendt, Lang Wang, Carlos Sanita
In the era of all-encompassing Big Data and the Internet of Things (IoT), mastery of Instrument Control (I&C) and SCADA systems deployment is becoming more important as the Operational Technology (OT) foundation for digital integration, data gathering, processing, analytics, and the optimization of business results. Integration and communication between different I&C and SCADA products and systems in an Oil and Gas project represent a significant challenge. The issues encountered on projects globally can prolong project schedules from weeks to months with consequential impacts on commercial gas production, project cash flow, and economics. This paper presents how to enable digital operations through holistic design, well-organized kickoff, effective Integrated Factory Acceptance Test (IFAT), and timely commissioning of I&C and SCADA systems for surface facilities of a gas field development project. It provides a feasible, economical and proven solution to address the foregoing challenges. Furthermore, in this paper we present a snapshot of how to use the latest data-science technology to bring out the value of the gold mine - big data generated by the I&C and SCADA systems.
{"title":"Digital Enablement Through Effective Deployment and Commissioning of Instrumentation, Supervisory Control and Data Acquisition System SCADA in Surface Facilities","authors":"Gaojing Cao, Xiangzen Wang, Lei Nie, Yaoqiang Hu, Yundong Xie, Gayatri P. Kartoatmodjo, Paul Williams, R. Henson, M. Zhu, Andrew Fendt, Lang Wang, Carlos Sanita","doi":"10.2118/208210-ms","DOIUrl":"https://doi.org/10.2118/208210-ms","url":null,"abstract":"\u0000 In the era of all-encompassing Big Data and the Internet of Things (IoT), mastery of Instrument Control (I&C) and SCADA systems deployment is becoming more important as the Operational Technology (OT) foundation for digital integration, data gathering, processing, analytics, and the optimization of business results.\u0000 Integration and communication between different I&C and SCADA products and systems in an Oil and Gas project represent a significant challenge. The issues encountered on projects globally can prolong project schedules from weeks to months with consequential impacts on commercial gas production, project cash flow, and economics.\u0000 This paper presents how to enable digital operations through holistic design, well-organized kickoff, effective Integrated Factory Acceptance Test (IFAT), and timely commissioning of I&C and SCADA systems for surface facilities of a gas field development project. It provides a feasible, economical and proven solution to address the foregoing challenges. Furthermore, in this paper we present a snapshot of how to use the latest data-science technology to bring out the value of the gold mine - big data generated by the I&C and SCADA systems.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82008712","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}
Alexey Vasilievich Timonov, R. Khabibullin, N. S. Gurbatov, A. R. Shabonas, Alexey Vladimirovich Zhuchkov
Geosteering is an important area and its quality determines the efficiency of formation drilling by horizontal wells, which directly affects the project NPV. This paper presents the automated geosteering optimization platform which is based on live well data. The platform implements online corrections of the geological model and forecasts well performance from the target reservoir. The system prepares recommendations of the best reservoir production interval and the direction for horizontal well placements based on reservoir performance analytics. This paper describes the stages of developing a comprehensive system using machine-learning methods, which allows multivariate calculations to refine and predict the geological model. Based on the calculations, a search for the optimal location of a horizontal well to maximize production is carried out. The approach realized in the work takes into account many factors (some specific features of geological structure, history of field development, wells interference, etc.) and can offer optimum horizontal well placement options without performing full-scale or sector hydrodynamic simulation. Machine learning methods (based on decision trees and neural networks) and target function optimization methods are used for geological model refinement and forecasting as well as for selection of optimum interval of well placement. As the result of researches we have developed the complex system including modules of data verification and preprocessing, automatic inter-well correlation, optimization and target interval selection. The system was tested while drilling hydrocarbons in the Western Siberian fields, where the developed approach showed efficiency.
{"title":"Automated Geosteering Optimization Using Machine Learning","authors":"Alexey Vasilievich Timonov, R. Khabibullin, N. S. Gurbatov, A. R. Shabonas, Alexey Vladimirovich Zhuchkov","doi":"10.2118/207364-ms","DOIUrl":"https://doi.org/10.2118/207364-ms","url":null,"abstract":"\u0000 Geosteering is an important area and its quality determines the efficiency of formation drilling by horizontal wells, which directly affects the project NPV.\u0000 This paper presents the automated geosteering optimization platform which is based on live well data. The platform implements online corrections of the geological model and forecasts well performance from the target reservoir. The system prepares recommendations of the best reservoir production interval and the direction for horizontal well placements based on reservoir performance analytics.\u0000 This paper describes the stages of developing a comprehensive system using machine-learning methods, which allows multivariate calculations to refine and predict the geological model. Based on the calculations, a search for the optimal location of a horizontal well to maximize production is carried out.\u0000 The approach realized in the work takes into account many factors (some specific features of geological structure, history of field development, wells interference, etc.) and can offer optimum horizontal well placement options without performing full-scale or sector hydrodynamic simulation.\u0000 Machine learning methods (based on decision trees and neural networks) and target function optimization methods are used for geological model refinement and forecasting as well as for selection of optimum interval of well placement.\u0000 As the result of researches we have developed the complex system including modules of data verification and preprocessing, automatic inter-well correlation, optimization and target interval selection.\u0000 The system was tested while drilling hydrocarbons in the Western Siberian fields, where the developed approach showed efficiency.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76024115","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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