Xingcai Wu, Yan Zhu, Xiaoying Liu, Song Zhang, Shang Gao, Jingang He, Hao Wu, Chunyao Wang, Yinzhu Ye, Guoyou Cui, Qiong Lu
Large scale polymer flooding in Daqing Oilfield achieved great success. The average recovery degree of these oilfields after polymer flooding has reached 52.5%, and the average water cut has reached 96.0%. It is urgent to find an effective technical method for further EOR. Targeting the highly dispersed remaining oil in the post polymer flooding reservoirs, the continuous phase polymer solution in ASP technology was replaced by nano-micron particle polymer dispersion to realize optimization for EOR mechanism, so the ASP technology was upgraded. The field test, has been completed the slug injection, and achieved obvious EOR effect. The ASP slug design with HPAM solution as the main displacement phase was abandoned. A type of water dispersion of nano-micron particle polymer as the main displacement phase was designed to replace the "P" in traditional ASP slug, so that the flowing control mechanism of "P" was optimized. Through synchronous diversion and displacement, it can initiate and sweep the remaining oil dispersed in relatively small pores. A large three-dimensional physical model with the size of 60 × 45 × 4.5cm was made to simulate the real development history of water injection and polymer flooding of the reservoir, based on which, the performance of the upgraded ASP was modeled. Furthermore, the program was designed and optimized by numerical simulation. The physical simulation fitting experiment of the development history of water flooding and polymer flooding shows that the coincidence rate is 93%+. After polymer flooding, the upgraded ASP further improved the recovery by 15.2 percent. The optimized scheme of numerical simulation is to inject 0.5PV of new ASP slug. Under the precondition of the historical recovery degree of 55.8% and water cut of 98.44%, the new ASP is expected to improve the recovery by 7.9% within 10 years. At present, the field test of ASP slug injection has just been completed, and remarkable results have been achieved, The daily oil production has increased by 60%, and the water oil ratio has decreased from 61.9 to 38.4. The daily oil production of some producers has increased by 2 to 3 times, and the recovery has increased by 5.2%. The field trial proves that the oil displacement mechanism of nano-micron-particle-polymer ASP flooding chemical system is more advanced and the displacement efficiency is higher than that of the traditional ASP flooding, and the oil recovery can be further enhanced for similar reservoirs under extreme conditions after polymer flooding. The traditional ASP technology is expected to have great upgrading and developing.
{"title":"A Successful Field Trial of a New ASP Technology in a\u0000High Water Cut and High Recovery Degree Reservoir After Polymer Flooding in North China","authors":"Xingcai Wu, Yan Zhu, Xiaoying Liu, Song Zhang, Shang Gao, Jingang He, Hao Wu, Chunyao Wang, Yinzhu Ye, Guoyou Cui, Qiong Lu","doi":"10.2523/iptc-22758-ea","DOIUrl":"https://doi.org/10.2523/iptc-22758-ea","url":null,"abstract":"\u0000 Large scale polymer flooding in Daqing Oilfield achieved great success. The average recovery degree of these oilfields after polymer flooding has reached 52.5%, and the average water cut has reached 96.0%. It is urgent to find an effective technical method for further EOR. Targeting the highly dispersed remaining oil in the post polymer flooding reservoirs, the continuous phase polymer solution in ASP technology was replaced by nano-micron particle polymer dispersion to realize optimization for EOR mechanism, so the ASP technology was upgraded. The field test, has been completed the slug injection, and achieved obvious EOR effect.\u0000 The ASP slug design with HPAM solution as the main displacement phase was abandoned. A type of water dispersion of nano-micron particle polymer as the main displacement phase was designed to replace the \"P\" in traditional ASP slug, so that the flowing control mechanism of \"P\" was optimized. Through synchronous diversion and displacement, it can initiate and sweep the remaining oil dispersed in relatively small pores. A large three-dimensional physical model with the size of 60 × 45 × 4.5cm was made to simulate the real development history of water injection and polymer flooding of the reservoir, based on which, the performance of the upgraded ASP was modeled. Furthermore, the program was designed and optimized by numerical simulation.\u0000 The physical simulation fitting experiment of the development history of water flooding and polymer flooding shows that the coincidence rate is 93%+. After polymer flooding, the upgraded ASP further improved the recovery by 15.2 percent. The optimized scheme of numerical simulation is to inject 0.5PV of new ASP slug. Under the precondition of the historical recovery degree of 55.8% and water cut of 98.44%, the new ASP is expected to improve the recovery by 7.9% within 10 years. At present, the field test of ASP slug injection has just been completed, and remarkable results have been achieved, The daily oil production has increased by 60%, and the water oil ratio has decreased from 61.9 to 38.4. The daily oil production of some producers has increased by 2 to 3 times, and the recovery has increased by 5.2%.\u0000 The field trial proves that the oil displacement mechanism of nano-micron-particle-polymer ASP flooding chemical system is more advanced and the displacement efficiency is higher than that of the traditional ASP flooding, and the oil recovery can be further enhanced for similar reservoirs under extreme conditions after polymer flooding. The traditional ASP technology is expected to have great upgrading and developing.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127556751","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}
T. Worawutthichanyakul, S. Hanchaiphiboolkul, T. Ketmalee, M. Pancharoen, Prang Sinhabaedya, Rungkarn Thammasanya, Chuthanart Rujipimolkit, Jantakan Srisuriyon, T. Roatkanjanaporn, Yannavit Sornsoongnoen, Parichat Srisen
In Pru Kratium (PKM) highly viscous oil reservoir, the secondary recovery method such as waterflood can adversely affect production due to an unfavorable mobility ratio, resulting in viscous fingering and early water breakthrough. Although polymer flooding which usually mitigates unfavorable mobility ratio, this technique also faces a challenge due to the high salinity formation water which may lead to excessive polymer consumption. To improve recovery, a special polymer injection scheme was designed and the small-scale pilot was initiated. After one year of injection, the pilot demonstrated that the polymer improved the sweep efficiency of the flood in both vertical and horizontal directions. Ultimately, the increase in oil recovery factor gain was 2.41%.
{"title":"Overcoming Challenges of Polymer Injection Pilot in High-Viscosity, High-Salinity Reservoir – A Case Study from Sirikit Oilfield, Thailand","authors":"T. Worawutthichanyakul, S. Hanchaiphiboolkul, T. Ketmalee, M. Pancharoen, Prang Sinhabaedya, Rungkarn Thammasanya, Chuthanart Rujipimolkit, Jantakan Srisuriyon, T. Roatkanjanaporn, Yannavit Sornsoongnoen, Parichat Srisen","doi":"10.2523/iptc-22766-ms","DOIUrl":"https://doi.org/10.2523/iptc-22766-ms","url":null,"abstract":"\u0000 In Pru Kratium (PKM) highly viscous oil reservoir, the secondary recovery method such as waterflood can adversely affect production due to an unfavorable mobility ratio, resulting in viscous fingering and early water breakthrough. Although polymer flooding which usually mitigates unfavorable mobility ratio, this technique also faces a challenge due to the high salinity formation water which may lead to excessive polymer consumption. To improve recovery, a special polymer injection scheme was designed and the small-scale pilot was initiated.\u0000 After one year of injection, the pilot demonstrated that the polymer improved the sweep efficiency of the flood in both vertical and horizontal directions. Ultimately, the increase in oil recovery factor gain was 2.41%.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115743260","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 objective of this study is to compare the performances of Underbalanced Coiled Tubing Drilling (UBCTD) versus conventional drilling with stimulation in a Permian carbonate target within a field in Saudi Arabia. The focus of this study is to ultimately investigate the effectiveness of biosteering in UBCTD compared to geosteering and subsequent stimulation in conventional drilling of vertical and horizontal wells within the same target. Biosteering is an application of biostratigraphy used to navigate and maintain well paths within the desired zone. This technique has been employed successfully in UBCTD wells in the Middle East. Biosteerers utilize the characteristic distribution of microfossil assemblages obtained from cuttings samples with the identification of biozones based on existing schemes. The most effective way to geosteer these well is to use this technique in conjunction with lithology descriptions, GR log trends, visible porosity and drilling parameters. UBCTD wells are not stimulated as there is minimal induced formation damage during drilling operations. Geosteering utilizes logging while drilling (LWD) in horizontal wells for lateral placement and to determine perforation intervals. Conventional wells in this study are all stimulated, employing multistage acid fracturing techniques. The dataset in this study comprises 50 wells, all of which are compared by normalized post-completion performance. Post-completion performance from the 50 well dataset was normalized to achieve a representative comparison. UBCTD biosteered wells show indicative superiority when compared to horizontal and vertical conventionally drilled and stimulated wells. In addition to the minimal formation damage in underbalanced wells, footage in the target is higher in biosteered UBCTD wells compared to geosteering. This is due to several reason with the main reason being is the ability of UBCTD to drill multiple laterals in each well, thus maximizing target contact. A detailed look into two wells targeting the same formation and field proved effective UBCTD utilization, yielding a production increase of several orders of magnitude. Despite these results, the normalized production performance may not account for significant LWD merits. In terms of steering, UBCTD slim-hole nature limits applications of available LWD technologies that provide essential information for reservoir characterization and development plans.
{"title":"Application of Biosteered Underbalanced Coiled Tubing Drilling in Optimizing Production","authors":"Faisal Alshuhail, M. Alsaad, Mahboob Alqahtani","doi":"10.2523/iptc-22931-ea","DOIUrl":"https://doi.org/10.2523/iptc-22931-ea","url":null,"abstract":"\u0000 \u0000 \u0000 The objective of this study is to compare the performances of Underbalanced Coiled Tubing Drilling (UBCTD) versus conventional drilling with stimulation in a Permian carbonate target within a field in Saudi Arabia. The focus of this study is to ultimately investigate the effectiveness of biosteering in UBCTD compared to geosteering and subsequent stimulation in conventional drilling of vertical and horizontal wells within the same target.\u0000 Biosteering is an application of biostratigraphy used to navigate and maintain well paths within the desired zone. This technique has been employed successfully in UBCTD wells in the Middle East. Biosteerers utilize the characteristic distribution of microfossil assemblages obtained from cuttings samples with the identification of biozones based on existing schemes. The most effective way to geosteer these well is to use this technique in conjunction with lithology descriptions, GR log trends, visible porosity and drilling parameters. UBCTD wells are not stimulated as there is minimal induced formation damage during drilling operations. Geosteering utilizes logging while drilling (LWD) in horizontal wells for lateral placement and to determine perforation intervals. Conventional wells in this study are all stimulated, employing multistage acid fracturing techniques. The dataset in this study comprises 50 wells, all of which are compared by normalized post-completion performance.\u0000 Post-completion performance from the 50 well dataset was normalized to achieve a representative comparison. UBCTD biosteered wells show indicative superiority when compared to horizontal and vertical conventionally drilled and stimulated wells. In addition to the minimal formation damage in underbalanced wells, footage in the target is higher in biosteered UBCTD wells compared to geosteering. This is due to several reason with the main reason being is the ability of UBCTD to drill multiple laterals in each well, thus maximizing target contact. A detailed look into two wells targeting the same formation and field proved effective UBCTD utilization, yielding a production increase of several orders of magnitude.\u0000 Despite these results, the normalized production performance may not account for significant LWD merits. In terms of steering, UBCTD slim-hole nature limits applications of available LWD technologies that provide essential information for reservoir characterization and development plans.\u0000","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"152 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115793279","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}
S. Hassig Fonseca, Richard Torres, Zhanke Liu, F. Jahn, G. Tagarot, S. Baca, H. Guevara, J. Botan, C. Villacres, J. Boas
Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even loss of a well. Despite general commonalities, each CT recovery can face unique challenges including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT. This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig-up, recovery pressure control equipment and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution. This case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline; an opening for deploying the wireline cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovering the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first documented such recovery case worldwide based on a thorough literature review.
{"title":"Challenges and Best Practices for Recovering Stuck Coiled Tubing Pipe Conveying a Cable","authors":"S. Hassig Fonseca, Richard Torres, Zhanke Liu, F. Jahn, G. Tagarot, S. Baca, H. Guevara, J. Botan, C. Villacres, J. Boas","doi":"10.2523/iptc-23093-ms","DOIUrl":"https://doi.org/10.2523/iptc-23093-ms","url":null,"abstract":"\u0000 Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even loss of a well. Despite general commonalities, each CT recovery can face unique challenges including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT.\u0000 This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig-up, recovery pressure control equipment and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution.\u0000 This case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline; an opening for deploying the wireline cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovering the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first documented such recovery case worldwide based on a thorough literature review.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132200454","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}
Eduardo Gramajo, Bodong Li, Sanguo Li, Yanbo Zong, R. Rached, S. A. Tella, G. Zhan
Downhole data transfer has been limited by slow downhole communication bandwidths for decades. The current data-transferring technologies have reached bottlenecks for acquiring logging data and ever-demanding high-frequency drilling dynamics measurements. There is an urgent need to significantly improve the downhole data communication speed for drilling optimization, real-time geosteering, and reservoir description. Current downhole communication systems with data rates between 20bit/s – 60kbit/s are not sufficient for the above-mentioned applications, let alone their limited robustness in structural integrity against inherent environmental noises and low cost-effectiveness make them less efficient. Therefore, a new downhole communication system using data microchips is proposed in this paper. The paper presents the improvements made to the first version of the data micro-storage-balls MSBs (Li et al., 2022) to adapt the system to 1) more complex drilling projects and 2) the acquisition of high-resolution and large datasets in a quasi-real-time for better well management decisions. The presented technology can transfer large amounts of data without needing a specific drill pipe connection or structure and employs the basic concept of a "flash drive" (downloading and exchanging data among systems). The equipment achieves time-devised data transmission using microchips stored in a sealed chamber which are released using a standard BHA sub. The upgrades to the first-generation MSB (larger memory capacity, robust packaging material, and added sensors) will improve multiple aspects of the technology. 1) The capability of deploying them in long horizontal sections and the recovery rate due to efficient housing density management (≤ 1.5 g/cm3) using high-performance hollow glass beads. 2) The increase in storage capacity (up to 32Gbit) with the use of state-of-the-art circuit boards that also support higher temperatures and pressures, improving the storage capacity, transmission rates, and overall tool performance in deep reservoir locations. Therefore, the newest additions and modifications made to the first generation of MSBs can create remarkable performance improvements.
几十年来，井下数据传输一直受到井下通信带宽缓慢的限制。目前的数据传输技术在获取测井数据和要求越来越高的高频钻井动态测量方面遇到了瓶颈。为了钻井优化、实时地质导向和油藏描述，迫切需要显著提高井下数据通信速度。目前数据速率在20bit/s - 60kbit/s之间的井下通信系统不足以满足上述应用，更不用说其结构完整性对固有环境噪声的鲁棒性和低成本效益使其效率降低。为此，本文提出了一种基于数据微芯片的井下通信系统。本文介绍了对第一版数据微存储球msb (Li et al.， 2022)的改进，以使系统适应1)更复杂的钻井项目，2)以准实时的方式获取高分辨率和大型数据集，以便更好地进行井管理决策。该技术可以传输大量数据，而无需特定的钻杆连接或结构，并采用了“闪存驱动器”的基本概念(在系统之间下载和交换数据)。该设备使用存储在密封腔室中的微芯片实现定时数据传输，这些微芯片使用标准BHA短节释放。第一代MSB的升级(更大的存储容量、坚固的封装材料和增加的传感器)将改进技术的多个方面。1)利用高性能中空玻璃微珠进行高效的壳体密度管理(≤1.5 g/cm3)，可将其部署在长水平段中，回收率高。2)通过使用最先进的电路板增加存储容量(高达32Gbit)，该电路板还支持更高的温度和压力，提高了深层油藏的存储容量、传输速率和整体工具性能。因此，对第一代msb进行的最新添加和修改可以显著提高性能。
{"title":"Large Capacity Data Microchip Transmission System and its Opportunities","authors":"Eduardo Gramajo, Bodong Li, Sanguo Li, Yanbo Zong, R. Rached, S. A. Tella, G. Zhan","doi":"10.2523/iptc-22972-ea","DOIUrl":"https://doi.org/10.2523/iptc-22972-ea","url":null,"abstract":"\u0000 Downhole data transfer has been limited by slow downhole communication bandwidths for decades. The current data-transferring technologies have reached bottlenecks for acquiring logging data and ever-demanding high-frequency drilling dynamics measurements. There is an urgent need to significantly improve the downhole data communication speed for drilling optimization, real-time geosteering, and reservoir description. Current downhole communication systems with data rates between 20bit/s – 60kbit/s are not sufficient for the above-mentioned applications, let alone their limited robustness in structural integrity against inherent environmental noises and low cost-effectiveness make them less efficient. Therefore, a new downhole communication system using data microchips is proposed in this paper.\u0000 The paper presents the improvements made to the first version of the data micro-storage-balls MSBs (Li et al., 2022) to adapt the system to 1) more complex drilling projects and 2) the acquisition of high-resolution and large datasets in a quasi-real-time for better well management decisions.\u0000 The presented technology can transfer large amounts of data without needing a specific drill pipe connection or structure and employs the basic concept of a \"flash drive\" (downloading and exchanging data among systems). The equipment achieves time-devised data transmission using microchips stored in a sealed chamber which are released using a standard BHA sub. The upgrades to the first-generation MSB (larger memory capacity, robust packaging material, and added sensors) will improve multiple aspects of the technology. 1) The capability of deploying them in long horizontal sections and the recovery rate due to efficient housing density management (≤ 1.5 g/cm3) using high-performance hollow glass beads. 2) The increase in storage capacity (up to 32Gbit) with the use of state-of-the-art circuit boards that also support higher temperatures and pressures, improving the storage capacity, transmission rates, and overall tool performance in deep reservoir locations. Therefore, the newest additions and modifications made to the first generation of MSBs can create remarkable performance improvements.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124434258","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}
Yousif M. B. Al-Asadi, G. Nasreldin, M. F. Al-shahwan
The giant Rumaila oilfield in south Iraq has been plagued by a number of wellbore instabilities. The shaley formations in this field pose the greatest challenges to drilling operations, accounting for approximately 90% of the problems. Stuck pipe, tight hole, and borehole collapse are examples of the incidents commonly encountered even while drilling vertical and deviated wells. This paper presents a well planning tool for translating the geomechanics simulation results to operational parameters, and in so doing, informing well trajectory planning and optimization. Specifically, the main objective was to generate shear failure mud weight cubes for different trajectories, The scenarios considered focused on examining the impact of depletion on field performance, drilling and well completion integrity for making life-of-reservoir decisions. The mechanical properties were first estimated along the trajectories of multiple 1D mechanical earth models (1D-MEMs) byutilizing available rock mechanics testing results, followed by geostatical populationin 3D space. The final 3D-MEM was calibrated against field observations.
{"title":"Drilling Weak Formations in Rumaila Field in Southern Iraq — Modelling Shear Failure Using Numerical Models","authors":"Yousif M. B. Al-Asadi, G. Nasreldin, M. F. Al-shahwan","doi":"10.2523/iptc-22926-ea","DOIUrl":"https://doi.org/10.2523/iptc-22926-ea","url":null,"abstract":"\u0000 The giant Rumaila oilfield in south Iraq has been plagued by a number of wellbore instabilities. The shaley formations in this field pose the greatest challenges to drilling operations, accounting for approximately 90% of the problems. Stuck pipe, tight hole, and borehole collapse are examples of the incidents commonly encountered even while drilling vertical and deviated wells.\u0000 This paper presents a well planning tool for translating the geomechanics simulation results to operational parameters, and in so doing, informing well trajectory planning and optimization. Specifically, the main objective was to generate shear failure mud weight cubes for different trajectories, The scenarios considered focused on examining the impact of depletion on field performance, drilling and well completion integrity for making life-of-reservoir decisions. The mechanical properties were first estimated along the trajectories of multiple 1D mechanical earth models (1D-MEMs) byutilizing available rock mechanics testing results, followed by geostatical populationin 3D space. The final 3D-MEM was calibrated against field observations.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115390913","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}
Modern broadband seismic data provides new regional insight into the underexplored deep-water offshore basin geometry of the Pase Sub-basin, from its basin segmentation with intra-basinal highs grabens to the development and prospectivity of syn-post-rift clastic reservoir sections proven in the prolific onshore area. The high degree of basin segmentation in the NW Sub-basin has led to the development of local depocenters in grabens with accumulation of thick clastic sections and potential for reservoirs sands. The clastic input and accumulation in the sub-basins were controlled by the intra basinal highs acting in periods as structural barriers disconnecting the grabens or as clastic input providers through erosion.
{"title":"Tertiary Deep Marine Syn-Rift to Shallow Marine-Deltaic Post-Rift Petroleum Plays in the Pase Sub-Basin, North Sumatra","authors":"J. Beenfeldt, E. Mueller, Chris Sim, T. Choi","doi":"10.2523/iptc-22804-ea","DOIUrl":"https://doi.org/10.2523/iptc-22804-ea","url":null,"abstract":"\u0000 Modern broadband seismic data provides new regional insight into the underexplored deep-water offshore basin geometry of the Pase Sub-basin, from its basin segmentation with intra-basinal highs grabens to the development and prospectivity of syn-post-rift clastic reservoir sections proven in the prolific onshore area. The high degree of basin segmentation in the NW Sub-basin has led to the development of local depocenters in grabens with accumulation of thick clastic sections and potential for reservoirs sands. The clastic input and accumulation in the sub-basins were controlled by the intra basinal highs acting in periods as structural barriers disconnecting the grabens or as clastic input providers through erosion.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122731394","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}
Despite the long exploration history, success rate has been low in the Khorat Plateau region of northeastern Thailand. To date, only two gas fields (from 9 discoveries) have been produced from Permian carbonate reservoirs, the only successful play. PTTEP and Department of Mineral Fuels (DMF) of Thailand conducted a collaborative basin-wide study using a Play-Based Exploration (PBE) method to fully understand the remaining prospectivity. PBE combines all aspects of petroleum system to provide a holistic view on basin prospectivity. It integrates existing knowledge in literature with well failure analysis, well-seismic stratigraphy, reconstruction of paleogeography and depositional environments, structural interpretation and restoration, source rock characterization and 1D basin modeling into a comprehensive basin development model. The outcome from these analyses coupled with better understanding of the basin were used to generate common risk segment maps of key elements in the petroleum system. The common risk segments maps were combined into the total chance map, which was then used to identify play fairways. Two major rifting episodes during Carboniferous-Triassic and three compressional events during the Triassic and Paleogene resulting in closures of the Paleo- and Neo-Tethys Oceans were responsible for the complex tectono-stratigraphic history of this area. The deposition of marine source rocks and carbonate reservoirs were influenced by the Late Carboniferous to Permian rift structures. The Triassic and Paleogene compression subsequently created prospective structural traps as well as modified local reservoir qualities via fracturing and hydrothermal processes. The Permian carbonate reservoirs are sealed by a widely distributed Upper Triassic fluvial floodplain sediments. Play chance shows that the exploration sweet spots are related to karst features and fractures mainly in the western and north-western parts of the Khorat Plateau. Further detailed study and prospect level evaluation planned for these fairways. Identifying and delineating the karst features and fractures are key to success in future exploration. Additional infill seismic data will also help in achieving the goals.
{"title":"Play-Based Evaluation on Permian Carbonate Reservoir: Implications for Petroleum Exploration in Northeast Thailand","authors":"Hendra Benny, T. Benjawan, Kasame Chaichana, Phinporn Amonpantang, Natsinee Wongsuriyakat, Sirichon Ponsri, Prath Piwhom, Phongsakorn Chaibamrung","doi":"10.2523/iptc-22828-ea","DOIUrl":"https://doi.org/10.2523/iptc-22828-ea","url":null,"abstract":"\u0000 Despite the long exploration history, success rate has been low in the Khorat Plateau region of northeastern Thailand. To date, only two gas fields (from 9 discoveries) have been produced from Permian carbonate reservoirs, the only successful play. PTTEP and Department of Mineral Fuels (DMF) of Thailand conducted a collaborative basin-wide study using a Play-Based Exploration (PBE) method to fully understand the remaining prospectivity. PBE combines all aspects of petroleum system to provide a holistic view on basin prospectivity. It integrates existing knowledge in literature with well failure analysis, well-seismic stratigraphy, reconstruction of paleogeography and depositional environments, structural interpretation and restoration, source rock characterization and 1D basin modeling into a comprehensive basin development model. The outcome from these analyses coupled with better understanding of the basin were used to generate common risk segment maps of key elements in the petroleum system. The common risk segments maps were combined into the total chance map, which was then used to identify play fairways. Two major rifting episodes during Carboniferous-Triassic and three compressional events during the Triassic and Paleogene resulting in closures of the Paleo- and Neo-Tethys Oceans were responsible for the complex tectono-stratigraphic history of this area. The deposition of marine source rocks and carbonate reservoirs were influenced by the Late Carboniferous to Permian rift structures. The Triassic and Paleogene compression subsequently created prospective structural traps as well as modified local reservoir qualities via fracturing and hydrothermal processes. The Permian carbonate reservoirs are sealed by a widely distributed Upper Triassic fluvial floodplain sediments. Play chance shows that the exploration sweet spots are related to karst features and fractures mainly in the western and north-western parts of the Khorat Plateau. Further detailed study and prospect level evaluation planned for these fairways. Identifying and delineating the karst features and fractures are key to success in future exploration. Additional infill seismic data will also help in achieving the goals.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125127387","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}
Takashi Nanjo, Akira Ebitani, Kazuaki Ishikawa, Yusaku Konishi, Keisuke Miyoshi, V. Shulakova, R. Beloborodov, R. Kempton, C. Delle Piane, Michael Benedict Clennell, Arun Sagotra, M. Pervukhina, Yuta Mizutani, Takuya Harada
Describing cuttings is routine work for wellsite geologists on a drill rig. The time-consuming nature of this analysis and the lack of consistency of the results between different interpreters are the two major concerns for this task. Wellsite geologists spend approximately 70% of their time on cuttings descriptions. In addition, 2 to 3 wellsite geologists are generally assigned to a drilling campaign, and they are replaced at the end of a shift. ML/AI techniques have the potential to solve these issues because of their advantages in prediction speed, objectivity, and consistency. The authors’ aim is to automate the task of cuttings descriptions with ML/AI techniques. We are targeting four lithologies, namely sandstone, mudstone, volcanic (volcanic rocks), and carbonate (carbonate rocks). The cuttings were collected from six wells in the Browse Basin (Australia). Of these four lithologies, a total of 1978 cuttings images were taken under a stereomicroscope. We chose a semantic segmentation technique using Convolutional Neural Network (CNN) algorithms to perform the image classification task. The images were labelled using the open-source annotation software. This annotated data were used for the network training. The labelled images were split into training, validation, and test sets. The accuracy of the trained model was evaluated using the intersection-over-union metric (IOU). The mean IOU of the final model on the validation dataset was 82.3%. Prediction results on the cuttings that are represented by single lithologies are qualitatively very accurate. On the other hand, the prediction for the non-typical lithology (e.g., siltstone, dark-colored volcanic rocks, mixed lithology samples) has room for improvement. The fragments with similar textures (e.g., dark colored volcanic and dark mudstone) are complex for the CNN to identify. The final goal of our project is not only the lithology identification but also the quantitative estimation of lithology abundances in the cuttings. Additional model improvements, such as hyperparameter optimization and significantly more training data, are required to accomplish this task successfully. The trained model for cuttings description has the potential to realize quantitative and high-speed cuttings description. Well-trained AI/ML models have the potential to assist well site geologists by automating the cuttings description process simplifying, speeding up and improving the consistency on the rig floor.
{"title":"Automatic Lithology Classification of Cuttings with Deep Learning","authors":"Takashi Nanjo, Akira Ebitani, Kazuaki Ishikawa, Yusaku Konishi, Keisuke Miyoshi, V. Shulakova, R. Beloborodov, R. Kempton, C. Delle Piane, Michael Benedict Clennell, Arun Sagotra, M. Pervukhina, Yuta Mizutani, Takuya Harada","doi":"10.2523/iptc-22867-ea","DOIUrl":"https://doi.org/10.2523/iptc-22867-ea","url":null,"abstract":"\u0000 Describing cuttings is routine work for wellsite geologists on a drill rig. The time-consuming nature of this analysis and the lack of consistency of the results between different interpreters are the two major concerns for this task. Wellsite geologists spend approximately 70% of their time on cuttings descriptions. In addition, 2 to 3 wellsite geologists are generally assigned to a drilling campaign, and they are replaced at the end of a shift. ML/AI techniques have the potential to solve these issues because of their advantages in prediction speed, objectivity, and consistency. The authors’ aim is to automate the task of cuttings descriptions with ML/AI techniques.\u0000 We are targeting four lithologies, namely sandstone, mudstone, volcanic (volcanic rocks), and carbonate (carbonate rocks). The cuttings were collected from six wells in the Browse Basin (Australia). Of these four lithologies, a total of 1978 cuttings images were taken under a stereomicroscope.\u0000 We chose a semantic segmentation technique using Convolutional Neural Network (CNN) algorithms to perform the image classification task. The images were labelled using the open-source annotation software. This annotated data were used for the network training. The labelled images were split into training, validation, and test sets.\u0000 The accuracy of the trained model was evaluated using the intersection-over-union metric (IOU). The mean IOU of the final model on the validation dataset was 82.3%. Prediction results on the cuttings that are represented by single lithologies are qualitatively very accurate. On the other hand, the prediction for the non-typical lithology (e.g., siltstone, dark-colored volcanic rocks, mixed lithology samples) has room for improvement. The fragments with similar textures (e.g., dark colored volcanic and dark mudstone) are complex for the CNN to identify. The final goal of our project is not only the lithology identification but also the quantitative estimation of lithology abundances in the cuttings. Additional model improvements, such as hyperparameter optimization and significantly more training data, are required to accomplish this task successfully.\u0000 The trained model for cuttings description has the potential to realize quantitative and high-speed cuttings description. Well-trained AI/ML models have the potential to assist well site geologists by automating the cuttings description process simplifying, speeding up and improving the consistency on the rig floor.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125558501","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Wilson, D. Povey, R. Davies, Pattarapong Prasongtham, Siriporn Shibano, T. Ampaiwan, I. N. Nuada, Farid Saifuddin
We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.
{"title":"3D Fault Seal Analysis of the Jasmine Field, Gulf of Thailand: Capillary Pressure Estimation and Calibration Using Fluid Contact Data","authors":"P. Wilson, D. Povey, R. Davies, Pattarapong Prasongtham, Siriporn Shibano, T. Ampaiwan, I. N. Nuada, Farid Saifuddin","doi":"10.2523/iptc-22831-ms","DOIUrl":"https://doi.org/10.2523/iptc-22831-ms","url":null,"abstract":"\u0000 We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127929262","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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