Maharaja Palanivel, M. Khalifa, Colby Fuser, Mohamed Seada, Eslam Farouk, Ashraf Abdel Baky, Ashraf Abdel Sattar, Yehia Ali, Ahmed Maher
To evaluate and report the benefits of artificial intelligence driven digital engineered breakdown in a pulsed fracturing technique that has been successfully applied for the first time globally in the western desert of Egypt. In this paper, we will discuss how the artificial intelligence driven digital engineered breakdown can affect the production performance of a pulsed fracturing treatment. When formation breakdown is controlled, there are several benefits observed in the fracture geometry and its placement. However, this has never been applied in a pulsed fracturing treatment where creating a dominant fracture is believed to provide better distribution of proppant agglomerates allowing for enhanced fracture conductivity created by void space between the agglomerates. The productivity benefits of the engineered breakdown will be evaluated. A treatment combining both the pulsing technique and the digital engineered breakdown will be reviewed in details such as well geographic data, reservoir quality, openhole log interpretation, pressure response and production models after matching actual data. The treatment will be compared with offset well that was treated with pulsed fracturing technique but without the digital engineered breakdown. Better pressure response was observed during the treatment and higher proppant concentrations were accepted by the formation with much favorable pressure response compared to offset wells. Post frac well tests indicate excellent production performance for the given reservoir quality observed from the logs in comparison to offset wells. Digital applications in fracturing have been recently improving the way we stimulate formations. This novel combination of pulsed fracturing and digital engineered breakdown shows productivity benefits that is crucial in current market conditions to maximize efficiency of operators assets.
{"title":"First Global Application Combining Digital Engineered Breakdown with Pulsing Technique for Highly Conductive Fractures with Proppant Agglomerates, Improving Subsurface Behavior and Maximizing Reservoir Productivity","authors":"Maharaja Palanivel, M. Khalifa, Colby Fuser, Mohamed Seada, Eslam Farouk, Ashraf Abdel Baky, Ashraf Abdel Sattar, Yehia Ali, Ahmed Maher","doi":"10.2118/209877-ms","DOIUrl":"https://doi.org/10.2118/209877-ms","url":null,"abstract":"\u0000 To evaluate and report the benefits of artificial intelligence driven digital engineered breakdown in a pulsed fracturing technique that has been successfully applied for the first time globally in the western desert of Egypt.\u0000 In this paper, we will discuss how the artificial intelligence driven digital engineered breakdown can affect the production performance of a pulsed fracturing treatment. When formation breakdown is controlled, there are several benefits observed in the fracture geometry and its placement. However, this has never been applied in a pulsed fracturing treatment where creating a dominant fracture is believed to provide better distribution of proppant agglomerates allowing for enhanced fracture conductivity created by void space between the agglomerates. The productivity benefits of the engineered breakdown will be evaluated.\u0000 A treatment combining both the pulsing technique and the digital engineered breakdown will be reviewed in details such as well geographic data, reservoir quality, openhole log interpretation, pressure response and production models after matching actual data. The treatment will be compared with offset well that was treated with pulsed fracturing technique but without the digital engineered breakdown.\u0000 Better pressure response was observed during the treatment and higher proppant concentrations were accepted by the formation with much favorable pressure response compared to offset wells. Post frac well tests indicate excellent production performance for the given reservoir quality observed from the logs in comparison to offset wells.\u0000 Digital applications in fracturing have been recently improving the way we stimulate formations. This novel combination of pulsed fracturing and digital engineered breakdown shows productivity benefits that is crucial in current market conditions to maximize efficiency of operators assets.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124741820","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}
Since the tight sandstone gas reservoir which is widely distributed in China has become increasingly important in oil field with the further development of resource, it is extraordinarily meaningful for the sustainable and healthy development of China’s energy industry to explore its benefit development mode. Though great achievements have made with the wide use of the hydraulic fracturing technology, which serves as an effective process measure to increase the productivity of a single well, in the development of global unconventional oil and gas resources, there have been many technical problems exposed. A critical one is that if the fractured stage length is too long, the oil and gas resources won’t be effectively exploited, and if it is too short, the operation cost and time will be increased apparently. Therefore, it is urgently required to make plans for determining the optimal length of the fractured reservoir based on different geological features of the oil and gas reservoirs. This paper took the tight oil reservoir in Lower Wuerhe formation in study area as the research case, determined 5 fracturing stage length cases combined with the treatment status and pumping injection procedure of M oil field: Case A (40m), Case B(50m), Case C (60m), Case D (70m) and Case E(80m), and realized fully 3D coupled simulation of the hydraulic fractures in H1 well based on the 3D geomechanical modeling and 3D DFN model with considering multiple factors including stress shadow, proppant settlement and migration using the unstructured grid technology to preprocess it to improve the capacity prediction accuracy of numerical simulation. The productivity prediction results showed that the 10-year EUR (Estimated Ultimate Recovery) of a single well ranged from 35,500 tons to 48,200 tons. With the comprehensive production and fracturing operation cost being considered comprehensively, it was recommended that the optimal length of the single fractured reservoir should be 60 meters.
致密砂岩气藏在中国广泛分布，随着资源的进一步开发，其在油田中的地位越来越重要，探索致密砂岩气藏的效益开发模式对中国能源工业的持续健康发展意义非凡。水力压裂技术作为提高单井产能的有效工艺措施，虽然在全球非常规油气资源开发中取得了巨大的成就，但也暴露出许多技术问题。关键是压裂段长度过长，油气资源无法得到有效开发;压裂段长度过短，作业成本和时间明显增加。因此，迫切需要根据油气藏的不同地质特征，规划确定裂缝性储层的最佳长度。本文以研究区下乌尔河组致密油储层为研究案例，结合M油田的处理现状和泵注工艺，确定了5个压裂段长案例:Case A (40m)、Case B(50m)、Case C (60m)、Case D (70m)和Case E(80m)，基于三维地质力学建模和三维DFN模型，综合考虑应力阴影、支撑剂沉降和运移等多种因素，利用非结构化网格技术对其进行预处理，实现了H1井水力裂缝的全三维耦合模拟，提高了数值模拟的容量预测精度。产能预测结果显示，单口井10年的EUR(估计最终采收率)在35500吨到48200吨之间。综合考虑生产和压裂作业成本，建议单裂缝储层最佳长度为60米。
{"title":"Multi-Stage Length Optimization with Integrated Hydraulic Fracture Propagation and Production Simulation Technology for Horizontal Wells in Unconventional Resource","authors":"Xiang Yuankai, Jianlin Zhou, Cheng Leiming, Ma Junxiu, Xingning Huang, Thanapol Singjaroen, Piyanuch Kieduppatum","doi":"10.2118/209909-ms","DOIUrl":"https://doi.org/10.2118/209909-ms","url":null,"abstract":"\u0000 Since the tight sandstone gas reservoir which is widely distributed in China has become increasingly important in oil field with the further development of resource, it is extraordinarily meaningful for the sustainable and healthy development of China’s energy industry to explore its benefit development mode. Though great achievements have made with the wide use of the hydraulic fracturing technology, which serves as an effective process measure to increase the productivity of a single well, in the development of global unconventional oil and gas resources, there have been many technical problems exposed. A critical one is that if the fractured stage length is too long, the oil and gas resources won’t be effectively exploited, and if it is too short, the operation cost and time will be increased apparently. Therefore, it is urgently required to make plans for determining the optimal length of the fractured reservoir based on different geological features of the oil and gas reservoirs. This paper took the tight oil reservoir in Lower Wuerhe formation in study area as the research case, determined 5 fracturing stage length cases combined with the treatment status and pumping injection procedure of M oil field: Case A (40m), Case B(50m), Case C (60m), Case D (70m) and Case E(80m), and realized fully 3D coupled simulation of the hydraulic fractures in H1 well based on the 3D geomechanical modeling and 3D DFN model with considering multiple factors including stress shadow, proppant settlement and migration using the unstructured grid technology to preprocess it to improve the capacity prediction accuracy of numerical simulation. The productivity prediction results showed that the 10-year EUR (Estimated Ultimate Recovery) of a single well ranged from 35,500 tons to 48,200 tons. With the comprehensive production and fracturing operation cost being considered comprehensively, it was recommended that the optimal length of the single fractured reservoir should be 60 meters.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123474061","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}
Veerawit Benjaboonyazit, Nithipoom Durongwattana, S. Buapha, Kittipat Wejwittayaklung, Phattarakorn Rangsriwong
The Company's digital transformation project was started in 2018 to overcome the challenge from digital disruption, energy transition and hydrocarbon reserves declination. Drilling and well engineering cluster is a key player in operating cost optimization which requires digestion and analysis of tons of data generated through daily operational reports. Thus, several digitalization projects have been initiated to optimize drilling and well process to be better, faster, and safer. In this paper, we intend to share a successful journey of digitalization under drilling and well cluster. The transformation journey started with identifying engineer's pain points in each process, among which the most common were redundant processes, manual data inputs/calculations, and time spent on collecting and analyzing unstructured data sources. Moreover, diversified practices on engineering programs and data analysis adversely affect well design standardization and optimizations. To counter those pain points, digital transformation projects were ideated by using digital solutions and technology which are grouped in 5 focus areas: centralized data platform, business intelligence, robotic process automation, digital assistant, and data analytics from fundamental to advance level respectively. Besides out-of-the-box solutions, many internally developed systems have been utilized throughout the journey which helps engineers to build their digital capability and awareness. There are over twenty (20) drilling and well digital projects implemented since the transformation project has been started. And as a result, engineers’ workload has been reduced significantly using digital solutions such as data extraction, visualization, and in-depth analysis. For example, the first successful project under robotic process automation utilizes text analytic and Artificial Intelligence (AI) techniques to analyze well conditions and integrity status from unstructured data and to generate reports within a limited timeframe. Another successful case is well design automated workflow which saved around 40% planning cycle time and provides a better design quality which will lead to a lower well cost. Total cost saving of over 40 mmusd has been recorded so far under the digital transformation project. Furthermore, there is an outlook for additional cost-saving through future new projects, integration, and scaling up plans across the company's international assets. The results and outcomes are very promising to this point. We believe that these initiatives will help the company to improve productivity, benefits, agility, and move beyond business disruptions. Combination of drilling and well expertise with digital transformation solutions will significantly improve well design process, quality and operational efficiency which make industry stay competitive and resilient in the future.
{"title":"Drilling and Well Digitalization, A Journey of Transformation","authors":"Veerawit Benjaboonyazit, Nithipoom Durongwattana, S. Buapha, Kittipat Wejwittayaklung, Phattarakorn Rangsriwong","doi":"10.2118/209872-ms","DOIUrl":"https://doi.org/10.2118/209872-ms","url":null,"abstract":"\u0000 The Company's digital transformation project was started in 2018 to overcome the challenge from digital disruption, energy transition and hydrocarbon reserves declination. Drilling and well engineering cluster is a key player in operating cost optimization which requires digestion and analysis of tons of data generated through daily operational reports. Thus, several digitalization projects have been initiated to optimize drilling and well process to be better, faster, and safer. In this paper, we intend to share a successful journey of digitalization under drilling and well cluster.\u0000 The transformation journey started with identifying engineer's pain points in each process, among which the most common were redundant processes, manual data inputs/calculations, and time spent on collecting and analyzing unstructured data sources. Moreover, diversified practices on engineering programs and data analysis adversely affect well design standardization and optimizations. To counter those pain points, digital transformation projects were ideated by using digital solutions and technology which are grouped in 5 focus areas: centralized data platform, business intelligence, robotic process automation, digital assistant, and data analytics from fundamental to advance level respectively. Besides out-of-the-box solutions, many internally developed systems have been utilized throughout the journey which helps engineers to build their digital capability and awareness.\u0000 There are over twenty (20) drilling and well digital projects implemented since the transformation project has been started. And as a result, engineers’ workload has been reduced significantly using digital solutions such as data extraction, visualization, and in-depth analysis. For example, the first successful project under robotic process automation utilizes text analytic and Artificial Intelligence (AI) techniques to analyze well conditions and integrity status from unstructured data and to generate reports within a limited timeframe. Another successful case is well design automated workflow which saved around 40% planning cycle time and provides a better design quality which will lead to a lower well cost.\u0000 Total cost saving of over 40 mmusd has been recorded so far under the digital transformation project. Furthermore, there is an outlook for additional cost-saving through future new projects, integration, and scaling up plans across the company's international assets. The results and outcomes are very promising to this point. We believe that these initiatives will help the company to improve productivity, benefits, agility, and move beyond business disruptions.\u0000 Combination of drilling and well expertise with digital transformation solutions will significantly improve well design process, quality and operational efficiency which make industry stay competitive and resilient in the future.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125559471","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 continental shale oil reservoirs usually have strong heterogeneity, which make the law of fracture propagation extremely complex, and the quantitative characterization of fracture network swept volume brings great challenges. In this paper, firstly, the facture shape of volume fracture is described preliminarily. Secondly, the volume fitting model of seam mesh transformation was established by coupling the key geological engineering parameters by multiple nonlinear regression method, and the productivity numerical simulation method was used to correct the reconstruction volume. Finally, a new concept of fracture network swept coefficient is put forward to quantitatively evaluate the fracturing effect. The study results shown that fractures created during the volume fracturing of shale oil reservoir appear as a belt network made up of main fractures primarily and branch fractures secondarily in the shape of cactus, and the main factors affecting the fracture network swept volume are fracturing fluid volume, fracture density, brittleness index, pump rate, horizontal stress difference, net pay thicknessand proppant amount. The prediction method is verified by the typical platform in the field to be accurate and reliable. It can provide scientific basis for the evaluation of volume fracturing effect of horizontal wells in shale oil reservoirs.
{"title":"A New Fracture Network Swept Volume Prediction Approach for Multi-Fractured Horizontal Wells in Shale Oil Reservoirs","authors":"Liang Tao, Ning Kang, Kejian Hu, Xianan Deng, Mirinuer Halifu, Yuhang Zhao","doi":"10.2118/209864-ms","DOIUrl":"https://doi.org/10.2118/209864-ms","url":null,"abstract":"\u0000 The continental shale oil reservoirs usually have strong heterogeneity, which make the law of fracture propagation extremely complex, and the quantitative characterization of fracture network swept volume brings great challenges. In this paper, firstly, the facture shape of volume fracture is described preliminarily. Secondly, the volume fitting model of seam mesh transformation was established by coupling the key geological engineering parameters by multiple nonlinear regression method, and the productivity numerical simulation method was used to correct the reconstruction volume. Finally, a new concept of fracture network swept coefficient is put forward to quantitatively evaluate the fracturing effect. The study results shown that fractures created during the volume fracturing of shale oil reservoir appear as a belt network made up of main fractures primarily and branch fractures secondarily in the shape of cactus, and the main factors affecting the fracture network swept volume are fracturing fluid volume, fracture density, brittleness index, pump rate, horizontal stress difference, net pay thicknessand proppant amount. The prediction method is verified by the typical platform in the field to be accurate and reliable. It can provide scientific basis for the evaluation of volume fracturing effect of horizontal wells in shale oil reservoirs.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"81 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114161223","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. Grant, Nuttapon Piyakunkiat, P. Bandyopadhyay, Kittipat Wejwittayaklung, Swee Hong Gary Ong, J. Manson, Pornchuda Konganuntragul, Khairul Abdul Rashid, Wararit Toempromraj, C. Chanpen, Mohamad Kamal Bin Hamdan, Prapapor Jantasuwanna, David Lewis
Field-X is a large offshore gas structure located 50 nautical miles from Miri City, Malaysia. The reservoir is a High-Pressure High-Temperature (HPHT) carbonate formation with high contaminants i.e., 1.8% mol of Hydrogen Sulfide (H2S) and 18% mol of Carbon Dioxide (CO2). This paper dwells on the completion design for the high-rate wells planned for this development. Exploration and appraisal wells showed severe reservoir properties that are "unique" as compared to other HPHT developments around the world. A multidisciplinary engineering team including HPHT drilling and completion specialists, production technologists, reservoir engineers, external specialist consultants, and facilities engineers are all working with a One Team One Goal mindset to address the challenges of completing this carbonate reservoir. Some of the completion design challenges addressed in this paper are Annular Pressure Management (APM) systems, perforation strategy for long intervals, well intervention philosophy, compaction and subsidence loading, thermal well interference due to the proximity of the platform well slots, HPHT monobore completion equipment design, qualification, and availability due to a very limited number of suppliers with long lead times. Another critical challenge addressed in this paper is an extensive material selection process to withstand the extremely corrosive well fluids, high temperature, and potential material cracking that historically has led to catastrophic consequences. As a result of the environment, exotic tubular materials are proposed based on intensive laboratory tests and computer simulations. Three-dimensional time history geomechanical and reservoir models explicitly detail the displacement compaction field which the downhole tubulars will be exposed in their lifetimes. Any annular pressure build-up will be handled by an APM system addressing the A, B, and C annuli with a permanent downhole gauge (PDG) installed for pressure and temperature monitoring tubing and annuli. These are some examples of the well design challenges tackled and resolved. The project is currently at the design phase, and all the thought process and design philosophies would be tested in this field. The authors wish that the lessons learned, engineering approaches, and design results will be useful in future sour HPHT completion developments.
{"title":"Challenges of a HPHT Completion Design with Extreme H2S and CO2 in a Carbonate Gas Development","authors":"C. Grant, Nuttapon Piyakunkiat, P. Bandyopadhyay, Kittipat Wejwittayaklung, Swee Hong Gary Ong, J. Manson, Pornchuda Konganuntragul, Khairul Abdul Rashid, Wararit Toempromraj, C. Chanpen, Mohamad Kamal Bin Hamdan, Prapapor Jantasuwanna, David Lewis","doi":"10.2118/209865-ms","DOIUrl":"https://doi.org/10.2118/209865-ms","url":null,"abstract":"\u0000 Field-X is a large offshore gas structure located 50 nautical miles from Miri City, Malaysia. The reservoir is a High-Pressure High-Temperature (HPHT) carbonate formation with high contaminants i.e., 1.8% mol of Hydrogen Sulfide (H2S) and 18% mol of Carbon Dioxide (CO2). This paper dwells on the completion design for the high-rate wells planned for this development. Exploration and appraisal wells showed severe reservoir properties that are \"unique\" as compared to other HPHT developments around the world. A multidisciplinary engineering team including HPHT drilling and completion specialists, production technologists, reservoir engineers, external specialist consultants, and facilities engineers are all working with a One Team One Goal mindset to address the challenges of completing this carbonate reservoir.\u0000 Some of the completion design challenges addressed in this paper are Annular Pressure Management (APM) systems, perforation strategy for long intervals, well intervention philosophy, compaction and subsidence loading, thermal well interference due to the proximity of the platform well slots, HPHT monobore completion equipment design, qualification, and availability due to a very limited number of suppliers with long lead times. Another critical challenge addressed in this paper is an extensive material selection process to withstand the extremely corrosive well fluids, high temperature, and potential material cracking that historically has led to catastrophic consequences.\u0000 As a result of the environment, exotic tubular materials are proposed based on intensive laboratory tests and computer simulations. Three-dimensional time history geomechanical and reservoir models explicitly detail the displacement compaction field which the downhole tubulars will be exposed in their lifetimes. Any annular pressure build-up will be handled by an APM system addressing the A, B, and C annuli with a permanent downhole gauge (PDG) installed for pressure and temperature monitoring tubing and annuli. These are some examples of the well design challenges tackled and resolved.\u0000 The project is currently at the design phase, and all the thought process and design philosophies would be tested in this field. The authors wish that the lessons learned, engineering approaches, and design results will be useful in future sour HPHT completion developments.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133805154","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}
Attawit Choodesh, W. Chantarataneewat, C. Ramirez, Mohd Hisyam Rosdi
One of the offshore gas fields, the formations are comprised of mixed deltaic and young shallow marine clastic sediments, which are considered among the shallowest unconsolidated and poorly sorted formations, with a high percentage of fines. Along with the sand production issue is the multiple stacked reservoirs that consist of interbedded sand-shale and laminations having undergone gas-water contact (GWC). The proximity of a water leg to the gas column also indicates likelihood of early water production. Water breakthrough can cause significant reserve loss in the gas reservoir and can be even more serious in the sand control completion, which creates a challenge when the two problems combine water and sand. Typical sand control treatments were high-rate water packs (HRWPs) and Extension packs (ExtPacs) or fracture for placement of proppant (FPP). The use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear thinning rheological properties and efficiently suspends sand in static condition. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with laboratory testing using reservoir cores to validate return permeability values). The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time using effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water shutoff treatment stage later as part of well life Applying the RPM process has not only reduced water production in these areas but has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application. Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid, consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of the RPM technique in sand-control completions also an option to treat wells after sand-control treatments and control water production resulting from nearby GWC
{"title":"Successfully Application of RPM in Sand Control Treatments for Offshore Field: Challenges, Results and Improvements","authors":"Attawit Choodesh, W. Chantarataneewat, C. Ramirez, Mohd Hisyam Rosdi","doi":"10.2118/209897-ms","DOIUrl":"https://doi.org/10.2118/209897-ms","url":null,"abstract":"\u0000 One of the offshore gas fields, the formations are comprised of mixed deltaic and young shallow marine clastic sediments, which are considered among the shallowest unconsolidated and poorly sorted formations, with a high percentage of fines. Along with the sand production issue is the multiple stacked reservoirs that consist of interbedded sand-shale and laminations having undergone gas-water contact (GWC). The proximity of a water leg to the gas column also indicates likelihood of early water production. Water breakthrough can cause significant reserve loss in the gas reservoir and can be even more serious in the sand control completion, which creates a challenge when the two problems combine water and sand.\u0000 Typical sand control treatments were high-rate water packs (HRWPs) and Extension packs (ExtPacs) or fracture for placement of proppant (FPP). The use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear thinning rheological properties and efficiently suspends sand in static condition. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with laboratory testing using reservoir cores to validate return permeability values). The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time using effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water shutoff treatment stage later as part of well life\u0000 Applying the RPM process has not only reduced water production in these areas but has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application. Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid, consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of the RPM technique in sand-control completions also an option to treat wells after sand-control treatments and control water production resulting from nearby GWC","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115331615","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}
Bobbywadi Richard, M. S. Saarani, S. Sulaiman, M. M. H. Meor Hashim, M. Arriffin, Rohaizat Ghazali
Significant technical challenges are prominent in today's oil and gas drilling operations, especially in remote locations with increasingly difficult geological settings. Stuck pipe incidents have become a major operational challenge, with events typically resulting in substantial amounts of lost time and associated costs. Real-time monitoring has emerged as an important tool to achieve drilling optimization in avoiding downtime, particularly stuck pipe events. With the addition of a predictive monitoring system, this process becomes much more effective and competent. Predictive monitoring is used for advanced real-time monitoring in the remote centre and operational workflows to aid in the drilling execution of complex or critical well sections. The emphasis will be on reducing the complexity of real-time data analysis by exploiting trends and anomalies between modelled and actual data to monitor wellbore conditions. This monitoring system and trend-based predictive capability enable drilling teams to detect borehole changes and take preventive action up to several hours in advance. Predictive monitoring can provide early warning of stuck pipe symptoms, allowing the rig and operations team to take corrective and step-by-step actions. The circumstances that lead to the stuck pipe can be difficult to detect as various factors may indicate potential problems. These are frequently missed until the situation has progressed to the point where the drill string becomes stuck. This system could have provided the rig crew with advance notice of changes in downhole conditions. An example of predictive monitoring adoption in a highly deviated extended reach well (ERD), with a 12,000ft long horizontal section is presented. It is exceptionally challenging in terms of geomechanics perspective as well as the well design. Predictive monitoring was implemented to assist drilling operation for the sidetracked well, and it had been completed successfully with minor hole condition issues. The predictive monitoring system is built around a trio of tightly coupled real-time dynamic models consisting of hydraulic, mechanical, and thermodynamic that simulate the wellbore state and physical processes during drilling operations. These models work simultaneously in a seamless process to assess drilling performance, borehole conditions, and related associated risks. It uses dynamic modelling to accurately model key drilling parameters and variables, allowing better monitoring.
{"title":"Deploying Dynamic Trend-Based Monitoring System to Deliver Real Time Drilling Decision","authors":"Bobbywadi Richard, M. S. Saarani, S. Sulaiman, M. M. H. Meor Hashim, M. Arriffin, Rohaizat Ghazali","doi":"10.2118/209869-ms","DOIUrl":"https://doi.org/10.2118/209869-ms","url":null,"abstract":"\u0000 Significant technical challenges are prominent in today's oil and gas drilling operations, especially in remote locations with increasingly difficult geological settings. Stuck pipe incidents have become a major operational challenge, with events typically resulting in substantial amounts of lost time and associated costs. Real-time monitoring has emerged as an important tool to achieve drilling optimization in avoiding downtime, particularly stuck pipe events. With the addition of a predictive monitoring system, this process becomes much more effective and competent. Predictive monitoring is used for advanced real-time monitoring in the remote centre and operational workflows to aid in the drilling execution of complex or critical well sections. The emphasis will be on reducing the complexity of real-time data analysis by exploiting trends and anomalies between modelled and actual data to monitor wellbore conditions. This monitoring system and trend-based predictive capability enable drilling teams to detect borehole changes and take preventive action up to several hours in advance. Predictive monitoring can provide early warning of stuck pipe symptoms, allowing the rig and operations team to take corrective and step-by-step actions. The circumstances that lead to the stuck pipe can be difficult to detect as various factors may indicate potential problems. These are frequently missed until the situation has progressed to the point where the drill string becomes stuck. This system could have provided the rig crew with advance notice of changes in downhole conditions. An example of predictive monitoring adoption in a highly deviated extended reach well (ERD), with a 12,000ft long horizontal section is presented. It is exceptionally challenging in terms of geomechanics perspective as well as the well design. Predictive monitoring was implemented to assist drilling operation for the sidetracked well, and it had been completed successfully with minor hole condition issues. The predictive monitoring system is built around a trio of tightly coupled real-time dynamic models consisting of hydraulic, mechanical, and thermodynamic that simulate the wellbore state and physical processes during drilling operations. These models work simultaneously in a seamless process to assess drilling performance, borehole conditions, and related associated risks. It uses dynamic modelling to accurately model key drilling parameters and variables, allowing better monitoring.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115358809","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 the field of drilling automation, most attention is usually focussed on the automating the mechanical side of the business and yet vast amounts of time and energy are spent by well engineers on designing and executing wells that may involve redesigns during the execution of the well due to subsurface uncertainty. This effort involves many people in the organisation, creates large amounts of documents and data that usually reside in different silos. The effort involved in pulling the right data together from different sources and checking that it's correct involves a lot of drudgery, hence it called be a ‘Cinderella’ task. There is a maxim that says that "If you can't measure you can't manage", but it's equally true that "if you can't analyse your measurements effectively and efficiently then you can't optimize", either for ROP or energy efficiency. This paper discusses the essential requirements for workflow optimization and drilling advisory systems, both as a business case in itself, but also as a reassuring steppingstone to full drilling automation. Significant advances in AI and Cloud Computing in the last decade have led to the ability to better automate the workflow process and allow real-time drilling advisory systems that allow a human-in-the-loop to react to and modify the drilling process. The essential parts of such are a workflow/optimisation system, no matter how good the AI, is that it should be intuitive, easy to use, vendor neutral, have robust data cleansing, be backed by 24/7 support, be customisable to the particular needs of the operation and flexible enough to work on different platforms yet allow expansion as new requirements are added. Operators are consistently wanting to centralise, then standardise, data flows for greater automated analysis and management. Using such a system, ROP improvements of over 18% have been seen in land operations, flat time reductions of 20% have been seen on offshore wells, weight to weight connection times have been reduced by over 35%, costly trips out of hole have been avoided due to MWD failure by directly comparing hole depth with offset well data in real time. With cloud-enabled, real-time AI, there is currently no limit on how ‘joined-up’ the drilling process can be, from rig scheduling through to production. Once confidence is gained by operators with drilling advisory systems and data quality then the next steps would be to hook these systems directly to drive rigs and tools with the human now as the monitor.
{"title":"Automated Workflows and Drilling Advisory Systems – The Cinderellas of Drilling Automation","authors":"Paul L. Francis","doi":"10.2118/209887-ms","DOIUrl":"https://doi.org/10.2118/209887-ms","url":null,"abstract":"\u0000 In the field of drilling automation, most attention is usually focussed on the automating the mechanical side of the business and yet vast amounts of time and energy are spent by well engineers on designing and executing wells that may involve redesigns during the execution of the well due to subsurface uncertainty. This effort involves many people in the organisation, creates large amounts of documents and data that usually reside in different silos. The effort involved in pulling the right data together from different sources and checking that it's correct involves a lot of drudgery, hence it called be a ‘Cinderella’ task. There is a maxim that says that \"If you can't measure you can't manage\", but it's equally true that \"if you can't analyse your measurements effectively and efficiently then you can't optimize\", either for ROP or energy efficiency. This paper discusses the essential requirements for workflow optimization and drilling advisory systems, both as a business case in itself, but also as a reassuring steppingstone to full drilling automation.\u0000 Significant advances in AI and Cloud Computing in the last decade have led to the ability to better automate the workflow process and allow real-time drilling advisory systems that allow a human-in-the-loop to react to and modify the drilling process. The essential parts of such are a workflow/optimisation system, no matter how good the AI, is that it should be intuitive, easy to use, vendor neutral, have robust data cleansing, be backed by 24/7 support, be customisable to the particular needs of the operation and flexible enough to work on different platforms yet allow expansion as new requirements are added. Operators are consistently wanting to centralise, then standardise, data flows for greater automated analysis and management.\u0000 Using such a system, ROP improvements of over 18% have been seen in land operations, flat time reductions of 20% have been seen on offshore wells, weight to weight connection times have been reduced by over 35%, costly trips out of hole have been avoided due to MWD failure by directly comparing hole depth with offset well data in real time.\u0000 With cloud-enabled, real-time AI, there is currently no limit on how ‘joined-up’ the drilling process can be, from rig scheduling through to production. Once confidence is gained by operators with drilling advisory systems and data quality then the next steps would be to hook these systems directly to drive rigs and tools with the human now as the monitor.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128867390","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 lessons learned and best practices using a scalable hydraulically actuated reamer shoe system for casing deployment. The technology was used in a few wells to successfully run 7 inch casing through problematic geological horizons where it had been impossible to do so with conventional float shoes. A scalable and customizable high speed reamer shoe technology was deployed in three wells right after a well in which the 7 inch long-string could not be deployed to objective depth and had to be set prematurely, leaving a lengthy rathole below the casing shoe. Consequently, the production zone had to be drilled and completed in 4 ½ inch. This ultra-high speed scalabe reamer shoe technology was then deployed in subsequent wells in an attempt to address this concern. Three 7 inch reamer shoes with two different configurations were deployed. Two were configured for LCM tolerance, whilst the third tool was tuned towards more optimal performance at lower circulating rates. The 7 inch casing strings were successfully deployed and cemented in all three wells. Tools with two variants of a new scalable, dual-chamber drive mechanism from the manufacturer were used. The major difference being in the flow pattern between the chambers. The LCM tolerant tools were the latest variant of the drive mechanism with a minimum restriction of 15mm, while the tool with the earlier variant of the scalable drive chamber, had a minimum restriction of 8 mm and a by-pass valve arrangement made up of 4 x 20mm ports. Activation flow rates were low though significantly different. The earlier tool activated at +/- 60 gpm whereas the more recent drive mechanism in the latest variant, activated at 26 gpm, indicative of a significant improvement in tool performance though configured for higher flow rates. Operating pressures were significantly higher in the earlier variant compared to the more recent drive mechanism. The differences in activation flow rates and operating pressures are due to how flow is altered and channeled through the drive mechanism as configured in each tool. All three tools were used to run 7 inch casing at low circulation (< 180 gpm) and successfully reamed through any obstructions encountered and cemented at target depth. The use of this technology was instrumental in successfully deploying all three 7 inch casing strings to objective depth. Due to its low flow capbilities (<180 gpm), PTTEP was able to successfully manage the tight pressure margin required to land casing and displace cement. Furthermore, the tool was evidently effective at circulating rates as low as 100 gpm and low operating pressures, making it ideal for most tubular deployment applications.
本文介绍了使用可扩展液压驱动扩眼器鞋系统下套管的经验教训和最佳实践。在几口井中，该技术成功地将7英寸的套管下入了有问题的地质层，而传统的浮子鞋无法做到这一点。在3口井中，由于7英寸长管柱无法下入目标深度，不得不提前下入，在套管鞋下方留下了一个很长的大孔，因此采用了可扩展、可定制的高速扩眼器鞋技术。因此，生产层必须在4.5英寸内钻完井。这种超高速可扩展扩眼器鞋技术随后被应用到后续的井中，试图解决这个问题。使用了3个7英寸扩眼器鞋，具有两种不同的配置。其中两个工具针对LCM公差进行了配置，而第三个工具则在较低循环速率下进行了优化。3口井均成功下入了7英寸套管，并进行了固井作业。使用了两种新型可扩展双腔驱动机构的工具。主要的区别在于腔室之间的流动模式。LCM容差工具是驱动机构的最新版本，最小限制为15mm，而早期版本的可扩展驱动室的工具，最小限制为8mm，旁通阀由4 x 20mm端口组成。激活流率虽低，但差异显著。早期的工具在+/- 60加仑/分的速度下启动，而最新版本的驱动机制在26加仑/分的速度下启动，这表明尽管配置了更高的流速，但工具性能有了显著改善。与最近的驱动机构相比，操作压力在早期的变型中明显更高。激活流量和作业压力的差异是由于每个工具中配置的驱动机构如何改变和引导流量。这三种工具都以低循环速度(< 180 gpm)下入了7英寸的套管，并成功地通过了遇到的任何障碍物，并在目标深度进行了固井。该技术的使用有助于成功将所有3个7英寸的套管柱下入目标深度。由于其低流量能力(<180 gpm)， PTTEP能够成功控制套管落地和置换水泥所需的紧压裕度。此外，该工具在低至100 gpm的循环速率和低工作压力下明显有效，使其成为大多数管状部署应用的理想选择。
{"title":"Reducing Drilling Risk Associated with Running Casing through Challenging Borehole Conditions with the Adoption of a Scalable Ultra-High Speed Hydraulically Actuated Reamer Shoe Technology","authors":"C. Nkwocha, Nipatsin Yimyam","doi":"10.2118/209920-ms","DOIUrl":"https://doi.org/10.2118/209920-ms","url":null,"abstract":"\u0000 This paper presents lessons learned and best practices using a scalable hydraulically actuated reamer shoe system for casing deployment. The technology was used in a few wells to successfully run 7 inch casing through problematic geological horizons where it had been impossible to do so with conventional float shoes.\u0000 A scalable and customizable high speed reamer shoe technology was deployed in three wells right after a well in which the 7 inch long-string could not be deployed to objective depth and had to be set prematurely, leaving a lengthy rathole below the casing shoe. Consequently, the production zone had to be drilled and completed in 4 ½ inch. This ultra-high speed scalabe reamer shoe technology was then deployed in subsequent wells in an attempt to address this concern. Three 7 inch reamer shoes with two different configurations were deployed. Two were configured for LCM tolerance, whilst the third tool was tuned towards more optimal performance at lower circulating rates. The 7 inch casing strings were successfully deployed and cemented in all three wells.\u0000 Tools with two variants of a new scalable, dual-chamber drive mechanism from the manufacturer were used. The major difference being in the flow pattern between the chambers. The LCM tolerant tools were the latest variant of the drive mechanism with a minimum restriction of 15mm, while the tool with the earlier variant of the scalable drive chamber, had a minimum restriction of 8 mm and a by-pass valve arrangement made up of 4 x 20mm ports. Activation flow rates were low though significantly different. The earlier tool activated at +/- 60 gpm whereas the more recent drive mechanism in the latest variant, activated at 26 gpm, indicative of a significant improvement in tool performance though configured for higher flow rates. Operating pressures were significantly higher in the earlier variant compared to the more recent drive mechanism. The differences in activation flow rates and operating pressures are due to how flow is altered and channeled through the drive mechanism as configured in each tool. All three tools were used to run 7 inch casing at low circulation (< 180 gpm) and successfully reamed through any obstructions encountered and cemented at target depth.\u0000 The use of this technology was instrumental in successfully deploying all three 7 inch casing strings to objective depth. Due to its low flow capbilities (<180 gpm), PTTEP was able to successfully manage the tight pressure margin required to land casing and displace cement. Furthermore, the tool was evidently effective at circulating rates as low as 100 gpm and low operating pressures, making it ideal for most tubular deployment applications.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"557 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127678615","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}
Abdul Afif Osman, Aulfah Azman, R. B. Sipangkui, M. N. S. Nazirmuddin, I. Aripin, Arie Muchalis Utta, M. Sujavudin, Sy M Shahril Sy Ahmad
Sustained annulus pressure is an increasingly common well integrity issue encountered particularly in aging platforms. The issue is normally discovered via periodic wellhead maintenance programs or during monitoring by the production team. Subsequently, the wells integrity team will pursue well diagnostic via annular pressure diagnostic by manipulating and creating specific conditions to acquire information on the potential leak rate, leak path, and source of the leak. The probable culprit of the tubular integrity issues is due to completion or casing leakages, or failed cement conditions. The generic rectification technique available varies from rig to rigless method. Considering the low economic of the field & remote jacket location with a small footprint and limited crane capacity in Sabah waters, either the rig or workover option can be unfavorable. Therefore, the options available to remediate the sustained annulus pressure are limited considering the platform's design and operational setup. Historically, the team has attempted with a conventional pump and lubricate the annulus to mitigate the symptoms. However, the effectiveness was questionable as the pressure kept creeping up within a short period which urged the team to look into better technology solutions. With the limitations above, the team warrants a new holistic approach to resolve the sustained annulus issue. Annulus Intervention System (AIS) provides better fluid conveyance and circulation for better fluid displacement at the targeted depth. The AIS system has a smaller footprint as compared to a pumping or workover unit which is a major advantage for a small and remote platform directly applicable to the target Sabah asset. This paper will table out the step-by-step method that has been taken by the team to ensure the AIS system is engineered and tailored to rectify the sustained annulus pressure in a less than 500-meter square deck space.
{"title":"Making Wells Safer; Rectification of High Annulus Pressure via Diagnostic and New Technologies Through Annulus Intervention Method","authors":"Abdul Afif Osman, Aulfah Azman, R. B. Sipangkui, M. N. S. Nazirmuddin, I. Aripin, Arie Muchalis Utta, M. Sujavudin, Sy M Shahril Sy Ahmad","doi":"10.2118/209882-ms","DOIUrl":"https://doi.org/10.2118/209882-ms","url":null,"abstract":"\u0000 Sustained annulus pressure is an increasingly common well integrity issue encountered particularly in aging platforms. The issue is normally discovered via periodic wellhead maintenance programs or during monitoring by the production team. Subsequently, the wells integrity team will pursue well diagnostic via annular pressure diagnostic by manipulating and creating specific conditions to acquire information on the potential leak rate, leak path, and source of the leak. The probable culprit of the tubular integrity issues is due to completion or casing leakages, or failed cement conditions.\u0000 The generic rectification technique available varies from rig to rigless method. Considering the low economic of the field & remote jacket location with a small footprint and limited crane capacity in Sabah waters, either the rig or workover option can be unfavorable. Therefore, the options available to remediate the sustained annulus pressure are limited considering the platform's design and operational setup. Historically, the team has attempted with a conventional pump and lubricate the annulus to mitigate the symptoms. However, the effectiveness was questionable as the pressure kept creeping up within a short period which urged the team to look into better technology solutions.\u0000 With the limitations above, the team warrants a new holistic approach to resolve the sustained annulus issue. Annulus Intervention System (AIS) provides better fluid conveyance and circulation for better fluid displacement at the targeted depth. The AIS system has a smaller footprint as compared to a pumping or workover unit which is a major advantage for a small and remote platform directly applicable to the target Sabah asset. This paper will table out the step-by-step method that has been taken by the team to ensure the AIS system is engineered and tailored to rectify the sustained annulus pressure in a less than 500-meter square deck space.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"81 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134071151","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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