In order to explore the benefits and potentials of digital transformation in China's offshore oilfields and improve the safety and efficiency of offshore oilfield's operations, China National Offshore Oil Corporation (CNOOC) has established a digital transformation pilot project in the Bohai Oilfield, which is not only the very first offshore digital transformation project but also the largest offshore oilfield in China. Integrating all aspects into one highly interactive system and utilizing the most advanced computational technologies, the pilot implementation provides seven modules to cover all aspects of field operations. To meet the needs for less human operation, reservoir visualization, collaborative operation and robust decision-making for offshore field development and production, the pilot implementation of digital transformation at Bohai Oilfield includes three parts, 1) information system construction; 2) intelligent transformation of offshore platform equipment and facilities; and 3) the construction of a control center on shore. All the parts above are carried out through the V&V (verification and validation) method, get good controls of data, technology, process and organization. The first part is an information system construction, which applied new technology in big data, artificial intelligence, cloud computing, internet of things and micro service architecture. It provides improved functions of safety management, reservoir management, production optimization and mobile inspection. The second part is intelligent transformation of offshore platform equipment and facilities, such as utilization of drones, robotics, personal digital assistant, intelligent water injection pump and so on. The application of these intelligent equipment and facilities not only can collect much more data about for production and systems optimization, but also can emancipate the labor force. The third part is the construction of a control center on shore, which is the decision center of the whole oilfield. Linked with data lake and optical fiber cable, the control center can achieve remote control for the works on the platform. The whole pilot project has been executed from scratch and started operation in July 2021. With the digital transformation, the digital coverage rate for core business is 100%; Once the system runs smoothly per design, the offshore operators are expected to be reduced by 50% due to high level of automation; the equipment failure rate is expected to decrease by 20% due to more intelligent and thorough inspection and maintenance; the incident rate is expected to lower by 20% due to more intelligent QHSE management and high-level of automation; and the reservoir recovery rate is expected to increase by 5% due to optimized reservoir management and well operations. This pilot is the very first digital transformation trial in offshore China. The project team studied examples from many national and internatio
{"title":"Pilot Construction of CNOOC Intelligent Oilfield for the Largest Offshore Oilfield in China","authors":"Jinman Li, Jianliang Zhou, Hongbo Huo, Shouwei Zhou, Yang Lin, Linsong Cheng","doi":"10.2523/iptc-22133-ms","DOIUrl":"https://doi.org/10.2523/iptc-22133-ms","url":null,"abstract":"\u0000 \u0000 \u0000 In order to explore the benefits and potentials of digital transformation in China's offshore oilfields and improve the safety and efficiency of offshore oilfield's operations, China National Offshore Oil Corporation (CNOOC) has established a digital transformation pilot project in the Bohai Oilfield, which is not only the very first offshore digital transformation project but also the largest offshore oilfield in China. Integrating all aspects into one highly interactive system and utilizing the most advanced computational technologies, the pilot implementation provides seven modules to cover all aspects of field operations.\u0000 \u0000 \u0000 \u0000 To meet the needs for less human operation, reservoir visualization, collaborative operation and robust decision-making for offshore field development and production, the pilot implementation of digital transformation at Bohai Oilfield includes three parts, 1) information system construction; 2) intelligent transformation of offshore platform equipment and facilities; and 3) the construction of a control center on shore. All the parts above are carried out through the V&V (verification and validation) method, get good controls of data, technology, process and organization.\u0000 The first part is an information system construction, which applied new technology in big data, artificial intelligence, cloud computing, internet of things and micro service architecture. It provides improved functions of safety management, reservoir management, production optimization and mobile inspection. The second part is intelligent transformation of offshore platform equipment and facilities, such as utilization of drones, robotics, personal digital assistant, intelligent water injection pump and so on. The application of these intelligent equipment and facilities not only can collect much more data about for production and systems optimization, but also can emancipate the labor force.\u0000 The third part is the construction of a control center on shore, which is the decision center of the whole oilfield. Linked with data lake and optical fiber cable, the control center can achieve remote control for the works on the platform.\u0000 \u0000 \u0000 \u0000 The whole pilot project has been executed from scratch and started operation in July 2021. With the digital transformation, the digital coverage rate for core business is 100%; Once the system runs smoothly per design, the offshore operators are expected to be reduced by 50% due to high level of automation; the equipment failure rate is expected to decrease by 20% due to more intelligent and thorough inspection and maintenance; the incident rate is expected to lower by 20% due to more intelligent QHSE management and high-level of automation; and the reservoir recovery rate is expected to increase by 5% due to optimized reservoir management and well operations.\u0000 \u0000 \u0000 \u0000 This pilot is the very first digital transformation trial in offshore China. The project team studied examples from many national and internatio","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"114 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90634665","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}
Well integrity in the oilfield is one of the challenges that petroleum engineers face, as they seek to monitor well corrosion in the field to optimize well performance. Most of these fields can be categorized as brownfields, with some of the wells considered aged and have expected integrity issues. To achieve sustainable production targets with cost-effective and safe operations from these fields requires a close monitoring of the integrity of all elements involved in the production chain. Addressing these challenges requires the engineers to coordinate and analyze several data elements, including casedhole, openhole, reservoir, well, and production data from multiple sources. Another challenge is to create and automate a corrosion workflow that saves the engineers’ time and improves efficiency. In this paper, we introduce an innovative workflow that uses the historical corrosion data while integrating the multiple production and reservoir variables. The innovative approach uses machine learning (ML) algorithms to provide a powerful tool for workover (W/O) candidate selection and for optimizing the corrosion evaluation frequency, which are required in different areas of the fields. Different ML methods (random forest classification and neural net) were applied on training data. Different models were created, and the best model will be used. This offered key insights on the rate of corrosion and corrosion patterns. Further, the developed workflow was designed to be self-sustaining and acting as a surveillance tool for monitoring the integrity of the wells. The first step of the workflow was to start with organizing and auditing the available corrosion data, followed by a review and analysis of existing openhole, casedhole, production, and reservoir engineering data. This approach led us to understand the extent and severity of corrosion in terms of the corrosion rate and the corrosion index. The corrosion logs were digitally interpreted depth-wise in order to explore the maximum metal loss for each interval. New animated conformance corrosion maps were created. The successful diagnosis through data analytics in a modern integrated software platform will assist in corrosion monitoring and decision-making. The multiple corrosion maps can be animated to visualize the current corrosion profile and predict the corrosion over time, in addition to ranking the wells for W/O candidate selection.
{"title":"Digital Solution to Extend the Life of Wells with Continuous Corrosion Monitoring based on Machine Learning Algorithms","authors":"M. Dallag, Mustafa Bawazir, A. Al-Ali","doi":"10.2523/iptc-22472-ms","DOIUrl":"https://doi.org/10.2523/iptc-22472-ms","url":null,"abstract":"\u0000 Well integrity in the oilfield is one of the challenges that petroleum engineers face, as they seek to monitor well corrosion in the field to optimize well performance. Most of these fields can be categorized as brownfields, with some of the wells considered aged and have expected integrity issues. To achieve sustainable production targets with cost-effective and safe operations from these fields requires a close monitoring of the integrity of all elements involved in the production chain. Addressing these challenges requires the engineers to coordinate and analyze several data elements, including casedhole, openhole, reservoir, well, and production data from multiple sources. Another challenge is to create and automate a corrosion workflow that saves the engineers’ time and improves efficiency.\u0000 In this paper, we introduce an innovative workflow that uses the historical corrosion data while integrating the multiple production and reservoir variables. The innovative approach uses machine learning (ML) algorithms to provide a powerful tool for workover (W/O) candidate selection and for optimizing the corrosion evaluation frequency, which are required in different areas of the fields. Different ML methods (random forest classification and neural net) were applied on training data. Different models were created, and the best model will be used. This offered key insights on the rate of corrosion and corrosion patterns. Further, the developed workflow was designed to be self-sustaining and acting as a surveillance tool for monitoring the integrity of the wells.\u0000 The first step of the workflow was to start with organizing and auditing the available corrosion data, followed by a review and analysis of existing openhole, casedhole, production, and reservoir engineering data. This approach led us to understand the extent and severity of corrosion in terms of the corrosion rate and the corrosion index. The corrosion logs were digitally interpreted depth-wise in order to explore the maximum metal loss for each interval. New animated conformance corrosion maps were created.\u0000 The successful diagnosis through data analytics in a modern integrated software platform will assist in corrosion monitoring and decision-making. The multiple corrosion maps can be animated to visualize the current corrosion profile and predict the corrosion over time, in addition to ranking the wells for W/O candidate selection.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78120351","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. A. Arias Ortiz, Lukasz Klimkowski, T. Finkbeiner, T. Patzek
Massive hydraulic fracturing stimulation generates complex induced fracture systems in shale reservoirs. The complexity increases in mudrock plays characterized by overpressure and associated small differential stresses. Such conditions favor interactions between induced vertical hydraulic fractures and mechanically weak bedding planes. When these planes delaminate easily, they may hydraulically stimulate large horizontal fracture components. In such situations, weak bedding planes are critical during hydraulic fracture propagation, impacting the fracture geometry and associated hydrocarbon production. We examine the effect of stimulated mechanically weak horizontal bedding planes on reservoir fluid production in multilayered mudrock plays distinguished by high pore pressure. We propose two idealized but viable geometries (‘fracture scenarios’) reported to occur in some overpressured shale plays. Our reference scenario comprises only vertical and planar hydraulically induced fractures. In the second geometry, we add stimulated horizontal bedding plane fractures that intersect the vertical hydraulic fractures. Next, we integrate the predetermined fracture geometries into a commercial reservoir simulator (CMG-IMEX) and assess the wellbore flow performance. Finally, we perform sensitivity analyses on horizontal fracture closure-mechanism, position and number of horizontal fractures, and reduced vertical fracture permeability. The results reveal that large horizontal fractures compromise hydrocarbon production. We conclude that horizontal fracture compressibility and vertical hydraulic fracture permeability are critical parameters during reservoir simulation. Compared with the reference scenario, the unpropped (i.e., highly compressible) and large stimulated horizontal fractures may reduce the initial oil production by 13% and the cumulative oil production at 15 years by 10%, assuming the highly conductive vertical hydraulic fractures. In contrast, horizontal fracture propagation results in shorter and narrower vertical hydraulic fractures. Thus, the lowered vertical hydraulic fracture conductivity predicts that initial oil production may decline by up to 77%. Finally, we show that vertical and planar hydraulic fractures geometry is not always an accurate assumption. This assumption may lead to an overestimation of hydrocarbon production during shale reservoir simulation studies. Our unique reservoir simulations show a numerical justification for the massive stimulation jobs and the unexpectedly low hydrocarbon production obtained in several mudrock plays worldwide. Consequently, we demonstrate that massive fracturing treatments may not always be a successful development method in mudrock plays.
{"title":"The Impact of Horizontal Bedding Plane Fractures on Reservoir Fluid Production in Shale Oil Plays with High Pore Pressure","authors":"D. A. Arias Ortiz, Lukasz Klimkowski, T. Finkbeiner, T. Patzek","doi":"10.2523/iptc-22213-ms","DOIUrl":"https://doi.org/10.2523/iptc-22213-ms","url":null,"abstract":"\u0000 Massive hydraulic fracturing stimulation generates complex induced fracture systems in shale reservoirs. The complexity increases in mudrock plays characterized by overpressure and associated small differential stresses. Such conditions favor interactions between induced vertical hydraulic fractures and mechanically weak bedding planes. When these planes delaminate easily, they may hydraulically stimulate large horizontal fracture components. In such situations, weak bedding planes are critical during hydraulic fracture propagation, impacting the fracture geometry and associated hydrocarbon production. We examine the effect of stimulated mechanically weak horizontal bedding planes on reservoir fluid production in multilayered mudrock plays distinguished by high pore pressure. We propose two idealized but viable geometries (‘fracture scenarios’) reported to occur in some overpressured shale plays. Our reference scenario comprises only vertical and planar hydraulically induced fractures. In the second geometry, we add stimulated horizontal bedding plane fractures that intersect the vertical hydraulic fractures. Next, we integrate the predetermined fracture geometries into a commercial reservoir simulator (CMG-IMEX) and assess the wellbore flow performance. Finally, we perform sensitivity analyses on horizontal fracture closure-mechanism, position and number of horizontal fractures, and reduced vertical fracture permeability. The results reveal that large horizontal fractures compromise hydrocarbon production. We conclude that horizontal fracture compressibility and vertical hydraulic fracture permeability are critical parameters during reservoir simulation. Compared with the reference scenario, the unpropped (i.e., highly compressible) and large stimulated horizontal fractures may reduce the initial oil production by 13% and the cumulative oil production at 15 years by 10%, assuming the highly conductive vertical hydraulic fractures. In contrast, horizontal fracture propagation results in shorter and narrower vertical hydraulic fractures. Thus, the lowered vertical hydraulic fracture conductivity predicts that initial oil production may decline by up to 77%. Finally, we show that vertical and planar hydraulic fractures geometry is not always an accurate assumption. This assumption may lead to an overestimation of hydrocarbon production during shale reservoir simulation studies. Our unique reservoir simulations show a numerical justification for the massive stimulation jobs and the unexpectedly low hydrocarbon production obtained in several mudrock plays worldwide. Consequently, we demonstrate that massive fracturing treatments may not always be a successful development method in mudrock plays.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75404555","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}
Ahmed BinGhanim, Jawad Al-Darweesh, M. Aljawad, Xianmin Zhou, M. Kamal, Zuhair AlYousif, M. Mahmoud
Foamed acidic fluids have been utilized in the industry for enhanced oil recovery and fracturing applications due to their various advantages. Flowback enhancement, recovery of treatment fluids, and reduction of overall water consumption per operation are examples of these advantages. This study examines the utilization of a chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA) in N2 and CO2 foamed fluids, which enhances the stability of foamed acidic fluids, lowers corrosion tendency, and is environmentally friendly. A modified high pressure and high temperature (HPHT) foam rheometer, and foam analyzer at ambient conditions, are used to test the acidic foamed fluids prepared in produced water using N2 and CO2. A screened out Alkyl diamine derivative surfactant has been tested at 212-300 °F and 1000 psi with and without GLDA. The effect of corrosion inhibitor addition on viscosity and foam quality is also investigated. Viscosity and foam quality measurements were done at increasing shear rates from 500 1/s up to 2000 1/s. Results showed that GLDA enhances the foamed fluid viscosity and stability. Resulted viscosities were in the range of 5 cP at higher shear rates to 25 cP in the lower shear rates region. Viscosity, in general, is lowered by higher shear rates, but foam quality is not affected. Fluid systems with a corrosion inhibitor also resulted in lower viscosities. The most stable and relatively higher viscosity values resulted from the 1 wt.% surfactant concentration with the addition of 15 wt.% GLDA and no corrosion inhibitor. Ambient conditions foam analyzer results showed higher foam height and half-life values of 182.8 mm and 16.5 minutes respectively when foaimg using N2 compared to 77.4 mm and 2.16 minutes when foamed with CO2. The addition of corrosion inhibitor showed significant negative impact in all cases, but least on the half-life of the CO2 foamed fluid. The rheology study provided did not consider the addition of thickeners which could be further investigated. This study covers the novel utilization of a chelating agent as an additive in CO2 and N2 acidic foamed fluids at harsh conditions. Furthermore, the fluid systems tested can be investigated and utilized as reliable stimulation fluid systems at temperatures up to 300 °F.
泡沫酸性流体由于其各种优点，已被用于提高石油采收率和压裂应用。增强返排、回收处理液和降低每次操作的总用水量都是这些优势的例子。本研究考察了l -谷氨酸- n, n -二乙酸(GLDA)螯合剂在N2和CO2泡沫流体中的应用，提高了泡沫酸性流体的稳定性，降低了腐蚀倾向，并且对环境友好。采用改进的高压高温(HPHT)泡沫流变仪和环境条件下的泡沫分析仪，对N2和CO2在采出水中制备的酸性泡沫流体进行了测试。筛选出的烷基二胺衍生物表面活性剂在212-300°F和1000 psi下进行了测试，有和没有GLDA。研究了缓蚀剂的加入对粘度和泡沫质量的影响。粘度和泡沫质量测量是在增加剪切速率从5001 /s到20001 /s的情况下进行的。结果表明，GLDA提高了泡沫流体的粘度和稳定性。结果表明，高剪切速率下黏度为5cp，低剪切速率下黏度为25cp。粘度，一般来说，降低较高的剪切速率，但泡沫质量不受影响。含有缓蚀剂的流体体系也可以降低粘度。表面活性剂浓度为1 wt.%， GLDA添加量为15 wt.%，不添加缓蚀剂时，粘度值相对较高且最稳定。环境条件泡沫分析仪结果显示，使用N2泡沫的泡沫高度和半衰期分别为182.8 mm和16.5分钟，而使用CO2泡沫的泡沫高度和半衰期分别为77.4 mm和2.16分钟。在所有情况下，缓蚀剂的加入都对CO2泡沫流体的半衰期有显著的负面影响，但对半衰期影响最小。所提供的流变学研究没有考虑增稠剂的加入，增稠剂可以进一步研究。本文研究了一种螯合剂在恶劣条件下作为CO2和N2酸性泡沫流体添加剂的新应用。此外，测试的流体系统可以在高达300°F的温度下作为可靠的增产流体系统进行研究和利用。
{"title":"Rheological Optimization of CO2 Foamed Chelating Stimulation Fluids at High-Pressure, High-Temperature, and Salinity","authors":"Ahmed BinGhanim, Jawad Al-Darweesh, M. Aljawad, Xianmin Zhou, M. Kamal, Zuhair AlYousif, M. Mahmoud","doi":"10.2523/iptc-22485-ms","DOIUrl":"https://doi.org/10.2523/iptc-22485-ms","url":null,"abstract":"\u0000 Foamed acidic fluids have been utilized in the industry for enhanced oil recovery and fracturing applications due to their various advantages. Flowback enhancement, recovery of treatment fluids, and reduction of overall water consumption per operation are examples of these advantages. This study examines the utilization of a chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA) in N2 and CO2 foamed fluids, which enhances the stability of foamed acidic fluids, lowers corrosion tendency, and is environmentally friendly.\u0000 A modified high pressure and high temperature (HPHT) foam rheometer, and foam analyzer at ambient conditions, are used to test the acidic foamed fluids prepared in produced water using N2 and CO2. A screened out Alkyl diamine derivative surfactant has been tested at 212-300 °F and 1000 psi with and without GLDA. The effect of corrosion inhibitor addition on viscosity and foam quality is also investigated. Viscosity and foam quality measurements were done at increasing shear rates from 500 1/s up to 2000 1/s.\u0000 Results showed that GLDA enhances the foamed fluid viscosity and stability. Resulted viscosities were in the range of 5 cP at higher shear rates to 25 cP in the lower shear rates region. Viscosity, in general, is lowered by higher shear rates, but foam quality is not affected. Fluid systems with a corrosion inhibitor also resulted in lower viscosities. The most stable and relatively higher viscosity values resulted from the 1 wt.% surfactant concentration with the addition of 15 wt.% GLDA and no corrosion inhibitor. Ambient conditions foam analyzer results showed higher foam height and half-life values of 182.8 mm and 16.5 minutes respectively when foaimg using N2 compared to 77.4 mm and 2.16 minutes when foamed with CO2. The addition of corrosion inhibitor showed significant negative impact in all cases, but least on the half-life of the CO2 foamed fluid. The rheology study provided did not consider the addition of thickeners which could be further investigated.\u0000 This study covers the novel utilization of a chelating agent as an additive in CO2 and N2 acidic foamed fluids at harsh conditions. Furthermore, the fluid systems tested can be investigated and utilized as reliable stimulation fluid systems at temperatures up to 300 °F.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75455700","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Ramdani, P. Khanna, Sander de Jong, G. Gairola, V. Vahrenkamp
High porosity-high permeability stromatoporoid/coral facies are important components of the Late Jurassic carbonate reservoirs in the Middle East. This facies exhibits sub-seismic depositional heterogeneities that subsurface models often overlook due to the limited interwell resolution of subsurface data. Understanding the effect of this facies on the 3D distribution of static reservoir properties and uncertainty in volumetric calculations of hydrocarbons in-place will improve estimates of the ultimate recovery and hence reservoir development decisions. A 3D high-fidelity outcrop-based geocellular depositional model that honors the spatial and petrophysical heterogeneity of the stromatoporoid/coral facies was constructed based on the Hanifa reservoir outcrop analog in central Saudi Arabia. The model was constructed from a 1.2 km × 1 km drone photogrammetry survey, measured sections (total length 150m) and spectral gamma-ray data, >200 thin sections, a 50 m-long core, a 19 km-long network of 2D and 3D Ground Penetrating Radar, and 600 m-long 2D seismic profiles. The facies model was populated with porosity and permeability equivalent to subsurface reservoir facies and utilized as the baseline petrophysical model for the comparison study. A set of pseudo wells at ~1 km spacing were simulated from the model capturing the model's 1D facies stacking and properties around the wellbore. The pseudo wells were utilized to stochastically build facies and static reservoir models scenarios to replicate the baseline model from limited well data. The volumetric calculation of each realization is compared with the baseline to investigate the range of volumetric uncertainty that would be introduced by the lateral distribution of stromatoporoid/coral facies. Early results show that depending upon the modeling methodology, the volumetric discrepancy between stochastic simulations and the deterministic outcrop baseline model is ~10-15%. Using a high-fidelity outcrop-based reservoir model, we have demonstrated the strong influence of 3D depositional heterogeneity of the stromatoporoid/coral facies on the uncertainty associated with hydrocarbon in-place volumes. We conclude that a static reservoir model can be significantly improved by using data-driven geological models that reflect the 3D heterogeneity of depositional facies.
高孔高渗层孔/珊瑚相是中东地区晚侏罗世碳酸盐岩储层的重要组成部分。该相表现出次地震沉积非均质性，由于地下资料的井间分辨率有限，地下模型常常忽略了这一点。了解该相对静态储层物性三维分布的影响，以及原位油气体积计算的不确定性，将有助于提高对最终采收率的估计，从而改善储层开发决策。以沙特阿拉伯中部的Hanifa油藏露头模拟为基础，建立了基于露头的三维高保真地胞体沉积模型，该模型考虑了叠层孔/珊瑚相的空间和岩石物理非均质性。该模型由1.2 km × 1 km无人机摄影测量、实测剖面(总长度150m)和光谱伽马射线数据、>200个薄片、50m长的岩心、19 km长的二维和三维探地雷达网络以及600 m长的二维地震剖面构建而成。该相模型填充了相当于地下储层相的孔隙度和渗透率，并作为对比研究的基准岩石物理模型。利用该模型模拟了一组间距约1 km的伪井，并捕捉了模型在井筒周围的一维相叠加和性质。利用拟井随机建立相和静态储层模型情景，从有限的井数据中复制基线模型。将每种实现的体积计算与基线进行比较，以研究叠层孔状/珊瑚相横向分布所带来的体积不确定性范围。早期结果表明，根据不同的建模方法，随机模拟与确定性露头基线模型之间的体积差异约为10-15%。利用基于露头的高保真油藏模型，我们证明了层孔/珊瑚相的三维沉积非均质性对与油气原位体积相关的不确定性的强烈影响。我们得出结论，通过使用反映沉积相三维非均质性的数据驱动地质模型，可以显著改善静态储层模型。
{"title":"How In-Place Volumes of Subsurface Reservoir Models are Impacted by Using 3d High-Resolution Outcrop Analogue Data. A Case Study Using Depositional Architectural Heterogeneity of Stromatoporoid/Coral Buildups of the Hanifa Fm, Saudi Arabia","authors":"A. Ramdani, P. Khanna, Sander de Jong, G. Gairola, V. Vahrenkamp","doi":"10.2523/iptc-21878-ms","DOIUrl":"https://doi.org/10.2523/iptc-21878-ms","url":null,"abstract":"\u0000 High porosity-high permeability stromatoporoid/coral facies are important components of the Late Jurassic carbonate reservoirs in the Middle East. This facies exhibits sub-seismic depositional heterogeneities that subsurface models often overlook due to the limited interwell resolution of subsurface data. Understanding the effect of this facies on the 3D distribution of static reservoir properties and uncertainty in volumetric calculations of hydrocarbons in-place will improve estimates of the ultimate recovery and hence reservoir development decisions. A 3D high-fidelity outcrop-based geocellular depositional model that honors the spatial and petrophysical heterogeneity of the stromatoporoid/coral facies was constructed based on the Hanifa reservoir outcrop analog in central Saudi Arabia. The model was constructed from a 1.2 km × 1 km drone photogrammetry survey, measured sections (total length 150m) and spectral gamma-ray data, >200 thin sections, a 50 m-long core, a 19 km-long network of 2D and 3D Ground Penetrating Radar, and 600 m-long 2D seismic profiles. The facies model was populated with porosity and permeability equivalent to subsurface reservoir facies and utilized as the baseline petrophysical model for the comparison study. A set of pseudo wells at ~1 km spacing were simulated from the model capturing the model's 1D facies stacking and properties around the wellbore. The pseudo wells were utilized to stochastically build facies and static reservoir models scenarios to replicate the baseline model from limited well data. The volumetric calculation of each realization is compared with the baseline to investigate the range of volumetric uncertainty that would be introduced by the lateral distribution of stromatoporoid/coral facies. Early results show that depending upon the modeling methodology, the volumetric discrepancy between stochastic simulations and the deterministic outcrop baseline model is ~10-15%. Using a high-fidelity outcrop-based reservoir model, we have demonstrated the strong influence of 3D depositional heterogeneity of the stromatoporoid/coral facies on the uncertainty associated with hydrocarbon in-place volumes. We conclude that a static reservoir model can be significantly improved by using data-driven geological models that reflect the 3D heterogeneity of depositional facies.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75717335","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Alvarez, X. Alarcon, Jonnathan Tellez, Younus Sameer, Mohammed Soran, Qader Rebeen
Historically, low-pressure, highly-fractured limestone formations have shown challenges in achieving proper acid diversion. In addition to the well deviation, this challenge becomes critical for wells close to the Water-Oil-Contact (WOC), with a latent likelihood to stimulate water zones. Consequently, a pinpoint placement technique thru Coiled Tubing (CT) plus a novel stimulation fluid is required to reduce/overcome this challenge. Common foamed acid has a short foam-stability time e.g., 10 minutes under native conditions. Hence, plain nitrified acid is pumped into the formation resulting in uneven treatment. Thus, custom foaming acids with stable foam qualities increments (e.g., 60% to 80%) are required to eliminate the risk of acid segregation to water zones. Then, wellbore fluids are over displaced by nitrogen, followed by the novel foamed acid with an initial bottom-hole foam quality of 60%, allowing the subsequent foamed stages (e.g., 65% to 80%) to divert upwards from the interval. Additionally, the CT mechanical diversion enables squeezing the treatment into the planned intervals. Carbonate reservoir stimulations in the north region of Iraq are performed using conventional hydrochloric acid (HCl) treatments. The foam acid diverting technology was implemented in challenging wells with a high risk of early water breakthrough based on water cut development in offset wells. Foamed matrix stimulation treatments were carried out through CT using a highly stable acid foam with self-diversion capability in ESP producer wells, demonstrating outstanding acid distribution over the interval of interest and sidestepping acid segregation to the water conductive zones. Despite the proximity of water zones, the use of foamed acids enhanced oil production and showcased a production gain of up to 3000 BOPD without water increase. The technology also allowed decreasing the volume of injected acid per meter of net interval by 41.7%, without jeopardizing the treatment efficacy which made it a cost-effective project. Based on the results, customized foamed acid treatments were incorporated in most of the stimulation programs. This paper discusses a novel foamed-acid system and the pinpoint placement technique used to stimulate challenging carbonate formations to get even fluid distribution, reducing the fluid segregation, thus minimizing the acid contact with the offending water zones.
{"title":"Implementing a New Foam-Acid Technology for Matrix Stimulation of Challenging Low Pressure, Naturally Fractured Carbonates Reservoirs: Case Studies, Northern Iraq","authors":"J. Alvarez, X. Alarcon, Jonnathan Tellez, Younus Sameer, Mohammed Soran, Qader Rebeen","doi":"10.2523/iptc-22603-ms","DOIUrl":"https://doi.org/10.2523/iptc-22603-ms","url":null,"abstract":"\u0000 Historically, low-pressure, highly-fractured limestone formations have shown challenges in achieving proper acid diversion. In addition to the well deviation, this challenge becomes critical for wells close to the Water-Oil-Contact (WOC), with a latent likelihood to stimulate water zones. Consequently, a pinpoint placement technique thru Coiled Tubing (CT) plus a novel stimulation fluid is required to reduce/overcome this challenge.\u0000 Common foamed acid has a short foam-stability time e.g., 10 minutes under native conditions. Hence, plain nitrified acid is pumped into the formation resulting in uneven treatment. Thus, custom foaming acids with stable foam qualities increments (e.g., 60% to 80%) are required to eliminate the risk of acid segregation to water zones. Then, wellbore fluids are over displaced by nitrogen, followed by the novel foamed acid with an initial bottom-hole foam quality of 60%, allowing the subsequent foamed stages (e.g., 65% to 80%) to divert upwards from the interval. Additionally, the CT mechanical diversion enables squeezing the treatment into the planned intervals.\u0000 Carbonate reservoir stimulations in the north region of Iraq are performed using conventional hydrochloric acid (HCl) treatments. The foam acid diverting technology was implemented in challenging wells with a high risk of early water breakthrough based on water cut development in offset wells.\u0000 Foamed matrix stimulation treatments were carried out through CT using a highly stable acid foam with self-diversion capability in ESP producer wells, demonstrating outstanding acid distribution over the interval of interest and sidestepping acid segregation to the water conductive zones.\u0000 Despite the proximity of water zones, the use of foamed acids enhanced oil production and showcased a production gain of up to 3000 BOPD without water increase. The technology also allowed decreasing the volume of injected acid per meter of net interval by 41.7%, without jeopardizing the treatment efficacy which made it a cost-effective project. Based on the results, customized foamed acid treatments were incorporated in most of the stimulation programs.\u0000 This paper discusses a novel foamed-acid system and the pinpoint placement technique used to stimulate challenging carbonate formations to get even fluid distribution, reducing the fluid segregation, thus minimizing the acid contact with the offending water zones.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81987460","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}
Y. Al-salali, Mansour Al-Awadhi, Abrar A. Hajjeyah, Muna Al-Shuaib, Alaa Al-Saleh, M. Useche, C. Vargas, Aditya Saxena, Osaretin Greg Idele
This paper presents an automated workflow that can estimate the oil and gas rates of a well, with the high frequency data, distinguishing the behavior of the reservoir under transient flow and pseudo steady state flow conditions. The new approach matches the wellhead pressure of a well model with the current value reported by a SCADA system, by adjusting the bottomhole pressure. For transient flow, it considers the response of the inflow performance relationship as a function of time. For pseudo steady state flow, it considers the declination of the reservoir pressure. The estimation of the production rate is carried out every 15 minutes, and the total daily produced volume is calculated based on the effective flowing time. To evaluate the accuracy of the new well rate estimation workflow, the output of the workflow is evaluated using two different criteria. Initially, the estimated oil and gas productions are compared with data from a real well test that is used as a quality control point. Secondly, considering that the fluid properties remain stable over time (water cut and gas-oil ratio), the critical flow through a choke valve defines a historical production trend that is used to quantify the deviation of the estimated values. As a result of the new workflow application, the difference between the estimated and measured rates decreased from 10% to 3%. The novelty of the new method is that it reduces the error of the estimated oil and gas production rates using the actual reservoir pressure behavior and provides more precise data for the different reservoir engineering analyzes.
{"title":"Automatic Production Rate Estimation Workflow Considering the Reservoir Flow Regime - Kuwait Integrated Digital Oilfield","authors":"Y. Al-salali, Mansour Al-Awadhi, Abrar A. Hajjeyah, Muna Al-Shuaib, Alaa Al-Saleh, M. Useche, C. Vargas, Aditya Saxena, Osaretin Greg Idele","doi":"10.2523/iptc-22258-ea","DOIUrl":"https://doi.org/10.2523/iptc-22258-ea","url":null,"abstract":"\u0000 This paper presents an automated workflow that can estimate the oil and gas rates of a well, with the high frequency data, distinguishing the behavior of the reservoir under transient flow and pseudo steady state flow conditions.\u0000 The new approach matches the wellhead pressure of a well model with the current value reported by a SCADA system, by adjusting the bottomhole pressure. For transient flow, it considers the response of the inflow performance relationship as a function of time. For pseudo steady state flow, it considers the declination of the reservoir pressure. The estimation of the production rate is carried out every 15 minutes, and the total daily produced volume is calculated based on the effective flowing time.\u0000 To evaluate the accuracy of the new well rate estimation workflow, the output of the workflow is evaluated using two different criteria. Initially, the estimated oil and gas productions are compared with data from a real well test that is used as a quality control point. Secondly, considering that the fluid properties remain stable over time (water cut and gas-oil ratio), the critical flow through a choke valve defines a historical production trend that is used to quantify the deviation of the estimated values. As a result of the new workflow application, the difference between the estimated and measured rates decreased from 10% to 3%.\u0000 The novelty of the new method is that it reduces the error of the estimated oil and gas production rates using the actual reservoir pressure behavior and provides more precise data for the different reservoir engineering analyzes.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83967200","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}
Ibrahim Al Awadhi, Ashok Sharma, Saleimah Al Zeyoudi
Amine Regenerator column is in operation since 1980 and severe internal corrosion / erosion observed since 2000 and subsequent local shell course replacement in 2015 and 2017 were done. Therefore, to avoid frequent maintenance and repair cost and to ensure long-term measure of integrity and availability of the equipment, it was concluded to replace the existing CS column with enhanced metallurgy The convectional approach of replacing the full column with CS +SS 3mm clad material which typically take around 12 month schedule for fabrication activities in dedicated shutdown in 2021. In addition, this replacement was planned to include replacement of full internals of amine column, existing foundation, pipe support and platform. Moreover, the execution strategy planned to be through FEED/EPC. However, looking for enhanced metallurgy and studying the local market stock of raw material and manufacturer have a big role to carry out the replacement job in planned shutdown in 2020 and within planned budget. The solution in going with solid SS vessel instead of clad will not only improve integrity but also will lead to enhanced schedule into 6.5 months and it is the most commercially attractive option. Moreover, going with solid SS material will reduce the fabrication time and avoid the issues associated with cladded materials and the requirements of the NDT due to welding job. In addition, it was planned to replace partially the column internals after reviewing the inspection history instead of replacing them fully. Further, the column and column internals procurement were accomplish with in in-house resources. The installation job of column, column internals, and foundation carried out within available planed June 2020 shutdown. The development of execution strategy/in-house engineering led to avoid of 35-days unit 2021 shutdown. Also, achieving direct cost saving of USD 1 million in procurement of Column and Column Internal from the planned budget. Further, the availability of SS solid material in UAE ex-stock and local manufacturer, were considered in minimizing the transportation and delivery schedule. The column replacement was the solution to tackle the repetitive corrosion/ thickness loss failures in the vessel. The way forward of replacing full column with SS solid material will improve integrity, enhanced delivery schedule, commercially it is an attractive option and has direct support to ADNOC ICV strategy. Hence, this job will avoid the dedicated 35 days in 2021 shutdown and accordingly the revenues losses of OPCOs shutdown
{"title":"Cost Effective Solution for Replacing Amine Columns","authors":"Ibrahim Al Awadhi, Ashok Sharma, Saleimah Al Zeyoudi","doi":"10.2523/iptc-22610-ea","DOIUrl":"https://doi.org/10.2523/iptc-22610-ea","url":null,"abstract":"\u0000 \u0000 \u0000 Amine Regenerator column is in operation since 1980 and severe internal corrosion / erosion observed since 2000 and subsequent local shell course replacement in 2015 and 2017 were done. Therefore, to avoid frequent maintenance and repair cost and to ensure long-term measure of integrity and availability of the equipment, it was concluded to replace the existing CS column with enhanced metallurgy\u0000 \u0000 \u0000 \u0000 The convectional approach of replacing the full column with CS +SS 3mm clad material which typically take around 12 month schedule for fabrication activities in dedicated shutdown in 2021. In addition, this replacement was planned to include replacement of full internals of amine column, existing foundation, pipe support and platform. Moreover, the execution strategy planned to be through FEED/EPC. However, looking for enhanced metallurgy and studying the local market stock of raw material and manufacturer have a big role to carry out the replacement job in planned shutdown in 2020 and within planned budget.\u0000 \u0000 \u0000 \u0000 The solution in going with solid SS vessel instead of clad will not only improve integrity but also will lead to enhanced schedule into 6.5 months and it is the most commercially attractive option. Moreover, going with solid SS material will reduce the fabrication time and avoid the issues associated with cladded materials and the requirements of the NDT due to welding job. In addition, it was planned to replace partially the column internals after reviewing the inspection history instead of replacing them fully. Further, the column and column internals procurement were accomplish with in in-house resources. The installation job of column, column internals, and foundation carried out within available planed June 2020 shutdown.\u0000 The development of execution strategy/in-house engineering led to avoid of 35-days unit 2021 shutdown. Also, achieving direct cost saving of USD 1 million in procurement of Column and Column Internal from the planned budget.\u0000 Further, the availability of SS solid material in UAE ex-stock and local manufacturer, were considered in minimizing the transportation and delivery schedule.\u0000 \u0000 \u0000 \u0000 The column replacement was the solution to tackle the repetitive corrosion/ thickness loss failures in the vessel. The way forward of replacing full column with SS solid material will improve integrity, enhanced delivery schedule, commercially it is an attractive option and has direct support to ADNOC ICV strategy. Hence, this job will avoid the dedicated 35 days in 2021 shutdown and accordingly the revenues losses of OPCOs shutdown\u0000","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84025048","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 point of well integrity is how to produce hydrocarbon from the source (well) to surface safely. The main goal of this paper is to keep well in operation due to gas supply and demand in the field, identify tubing/ annulus communication, mitigate any excessive annulus pressure, and corrective action of tubing casing leaks refer to industrial code and Well Integrity Management System (WIMS). One of the wells in "P" platform, namely "W" well has found a leak between production tubing and production casing ("A" annulus) and no any excessive presure from "B" & "C" annulus in this case. There is no way to shut-in the well due to gas supply and demand in our field and the well must be operate safely by conduct annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modify surface facilities. Pressure limit is calculated by determine MAASP and MOASP to ensure working pressure and bleed-off program are managed. Annulus pressure bleed-down program is one of mitigation action to manage excessive pressure in annulus. We have provided technical recommendation, specify mitigate engineering solution to reduce risks, and modify surface facilities to keep wells in operation. Based on jobs result, we have done to operate all wells safely with efficient technology, deliver fluid from 3 ½" production tubing to surface facilities, perform cost optimization, and minimize production loss. We have also performed to manage and maintain annulus casing pressure successfully related to well integrity implementation. Furthermore, In this case, there is no serious hazard during these conditions in offshore field. The paper will share success story, method, and detail procedure to keep well operation by maintain annulus casing pressure in offshore field. We have done this method by efficient technology/ solution with lower operating & construction cost and there is no production loss during operation. We confidence this method can be applied successfully not only for our field, but also other business/ operating units which has similar conditions.
{"title":"An Efficient Technology and Solution Well Operation by Maintain Well Integrity in Offshore Field","authors":"Edyos Wyndu Saleppang Kila, Dadang Firmansyah","doi":"10.2523/iptc-22470-ea","DOIUrl":"https://doi.org/10.2523/iptc-22470-ea","url":null,"abstract":"\u0000 The point of well integrity is how to produce hydrocarbon from the source (well) to surface safely. The main goal of this paper is to keep well in operation due to gas supply and demand in the field, identify tubing/ annulus communication, mitigate any excessive annulus pressure, and corrective action of tubing casing leaks refer to industrial code and Well Integrity Management System (WIMS).\u0000 One of the wells in \"P\" platform, namely \"W\" well has found a leak between production tubing and production casing (\"A\" annulus) and no any excessive presure from \"B\" & \"C\" annulus in this case. There is no way to shut-in the well due to gas supply and demand in our field and the well must be operate safely by conduct annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modify surface facilities.\u0000 Pressure limit is calculated by determine MAASP and MOASP to ensure working pressure and bleed-off program are managed. Annulus pressure bleed-down program is one of mitigation action to manage excessive pressure in annulus. We have provided technical recommendation, specify mitigate engineering solution to reduce risks, and modify surface facilities to keep wells in operation. Based on jobs result, we have done to operate all wells safely with efficient technology, deliver fluid from 3 ½\" production tubing to surface facilities, perform cost optimization, and minimize production loss. We have also performed to manage and maintain annulus casing pressure successfully related to well integrity implementation. Furthermore, In this case, there is no serious hazard during these conditions in offshore field.\u0000 The paper will share success story, method, and detail procedure to keep well operation by maintain annulus casing pressure in offshore field. We have done this method by efficient technology/ solution with lower operating & construction cost and there is no production loss during operation. We confidence this method can be applied successfully not only for our field, but also other business/ operating units which has similar conditions.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80724802","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}
There are high emphasis and expectations placed on obtaining the most accurate depth structure map from seismic data. These maps set the expectations, for drilling depth prognosis and hydrocarbon volumetric estimation of reservoirs. The viability of a hydrocarbon prospect and the success of drilling to tap the resources heavily relies on depth map accuracies. However, achieving precisions have been challenging due to the limitations of the seismic data. This paper describes a novel integrated depth modeling workflow that successfully quantifies the depth uncertainties through a geostatistical simulation-based approach of integrating seismic interpretation inputs, well tops, and seismic velocity together with their associated uncertainties. The method proposed to conciliate seismic uncertainties and to address structural depth uncertainty is called stochastic time to depth conversion. It is a geostatistical driven approach that uses Bayesian Co-Kriging and relies on well depth markers using appropriate time-derived external drifts. The method accounts for uncertainties attached to the seismic time of events picked and velocity uncertainty integrated into a single stochastic workflow. Time Uncertainty is related to the seismic data quality aspects such as resolution limit and tunning thickness and velocity uncertainty is due to imperfectness of the velocity model due to anisotropy or inaccuracies in velocity picking. Both uncertainties can be defined by a 1st standard deviation sigma value or defined by a lateral varying sigma map. Realizations of depth maps are simulated, and the best-estimated depth map is produced. A confidence interval that envelopes the multiple realized horizons can provide meaningful measures of depth uncertainty for drilling depth prognosis giving a window of anticipation of where the top of the reservoir may be encountered. The stochastic approach allows for proper quantification of gross rock volume (GRV) uncertainty which impacts hydrocarbon in-place estimations. Ranking of all GRV outcomes is now possible using the expectation curve where the P10, P50, and the P90 volumes and associated maps can be identified. These maps could then contribute to structural modeling of the low, base, and high case scenarios allowing for hydrocarbon in-place sensitivity analysis. The geostatistics-based time-to-depth method offers a consistent framework to address the bias at the core of the upstream Front-End Loading (FEL) process which ultimately maximizes the accuracy of depth models and improved E&P decision-making. The method is based on Bayesian Co-Kriging and offers the consistent integration of all sources of uncertainty throughout all layers within a unique probability model. Field data applications show that the stochastic depth modeling method is reliable due to its strong dependence on mathematically sound geostatistical principles, scalable that integrates the sequential processes.
{"title":"A Probabilistic Unified Depth Velocity Model and Associated Uncertainties Estimation Based on Bayesian Approach","authors":"Wei Long Liew, S. Rajput","doi":"10.2523/iptc-21898-ea","DOIUrl":"https://doi.org/10.2523/iptc-21898-ea","url":null,"abstract":"\u0000 There are high emphasis and expectations placed on obtaining the most accurate depth structure map from seismic data. These maps set the expectations, for drilling depth prognosis and hydrocarbon volumetric estimation of reservoirs. The viability of a hydrocarbon prospect and the success of drilling to tap the resources heavily relies on depth map accuracies. However, achieving precisions have been challenging due to the limitations of the seismic data.\u0000 This paper describes a novel integrated depth modeling workflow that successfully quantifies the depth uncertainties through a geostatistical simulation-based approach of integrating seismic interpretation inputs, well tops, and seismic velocity together with their associated uncertainties. The method proposed to conciliate seismic uncertainties and to address structural depth uncertainty is called stochastic time to depth conversion. It is a geostatistical driven approach that uses Bayesian Co-Kriging and relies on well depth markers using appropriate time-derived external drifts. The method accounts for uncertainties attached to the seismic time of events picked and velocity uncertainty integrated into a single stochastic workflow. Time Uncertainty is related to the seismic data quality aspects such as resolution limit and tunning thickness and velocity uncertainty is due to imperfectness of the velocity model due to anisotropy or inaccuracies in velocity picking. Both uncertainties can be defined by a 1st standard deviation sigma value or defined by a lateral varying sigma map. Realizations of depth maps are simulated, and the best-estimated depth map is produced. A confidence interval that envelopes the multiple realized horizons can provide meaningful measures of depth uncertainty for drilling depth prognosis giving a window of anticipation of where the top of the reservoir may be encountered.\u0000 The stochastic approach allows for proper quantification of gross rock volume (GRV) uncertainty which impacts hydrocarbon in-place estimations. Ranking of all GRV outcomes is now possible using the expectation curve where the P10, P50, and the P90 volumes and associated maps can be identified. These maps could then contribute to structural modeling of the low, base, and high case scenarios allowing for hydrocarbon in-place sensitivity analysis. The geostatistics-based time-to-depth method offers a consistent framework to address the bias at the core of the upstream Front-End Loading (FEL) process which ultimately maximizes the accuracy of depth models and improved E&P decision-making. The method is based on Bayesian Co-Kriging and offers the consistent integration of all sources of uncertainty throughout all layers within a unique probability model. Field data applications show that the stochastic depth modeling method is reliable due to its strong dependence on mathematically sound geostatistical principles, scalable that integrates the sequential processes.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77712385","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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