Y. Svec, O. Kindi, M. Sawafi, R. Farajzadeh, Hanaa Al Sulaimani, Jasper Van Berkel, S. Al-hinai, Moh’d Al Abri, S. Nofli, A. Al-Yahyai, M. Al-Mahrooqi
Polymer outage (or polymer injection unavailability) is undesirable but also inevitable. When it happens, the question is how to respond to it to minimize its adverse impact on the production. This paper presents the rationale for generating a polymer outage strategy to operate a polymer flood field in the southern area of the Sultanate of Oman. The work presented here is based on field performance and analytical analysis. The diagnostic plots were created from 10 years of polymer flood field response and were used for this operating decision. The pros and cons of two scenarios were discussed. The selected operational strategy is to minimize the short falls of polymer outage. The strategy was implemented in the field. Simultaneous injection and production pause (SIPP) is recommended for the full field polymer outage. It minimizes the impact on polymer incremental oil and hence less deferment. Calibrated with the actual results, analytical method is used to determine when to shut down and whether a short of buffer period of water can be tolerated before SIPP is carried out. The polymer literature focus on polymer mechanisms, modeling, project initiation and implementation but no paper discusses the operational strategy on how to respond to field polymer outages. This paper shares our operational learnings and the field results of various polymer operation modes on polymer incremental oil. The learning from this field may be of interest to other operators who are planning or currently implementing polymer flood in their fields.
{"title":"Polymer Outage Strategy for On-Going Polymer Injection Operation in the Sultanate of Oman","authors":"Y. Svec, O. Kindi, M. Sawafi, R. Farajzadeh, Hanaa Al Sulaimani, Jasper Van Berkel, S. Al-hinai, Moh’d Al Abri, S. Nofli, A. Al-Yahyai, M. Al-Mahrooqi","doi":"10.2118/208202-ms","DOIUrl":"https://doi.org/10.2118/208202-ms","url":null,"abstract":"\u0000 Polymer outage (or polymer injection unavailability) is undesirable but also inevitable. When it happens, the question is how to respond to it to minimize its adverse impact on the production. This paper presents the rationale for generating a polymer outage strategy to operate a polymer flood field in the southern area of the Sultanate of Oman. The work presented here is based on field performance and analytical analysis. The diagnostic plots were created from 10 years of polymer flood field response and were used for this operating decision. The pros and cons of two scenarios were discussed. The selected operational strategy is to minimize the short falls of polymer outage. The strategy was implemented in the field.\u0000 Simultaneous injection and production pause (SIPP) is recommended for the full field polymer outage. It minimizes the impact on polymer incremental oil and hence less deferment. Calibrated with the actual results, analytical method is used to determine when to shut down and whether a short of buffer period of water can be tolerated before SIPP is carried out.\u0000 The polymer literature focus on polymer mechanisms, modeling, project initiation and implementation but no paper discusses the operational strategy on how to respond to field polymer outages. This paper shares our operational learnings and the field results of various polymer operation modes on polymer incremental oil. The learning from this field may be of interest to other operators who are planning or currently implementing polymer flood in their fields.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75635914","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}
Hélio Alves Pedrosa, F. Colbert, F. Garcia, R. Gachet, Alberto Carlos Boldrini, Jose Marcio De Souza, Marcelo Oliveira Carrara, R. Okullo, Joan Hernandez Belisario, Ly Amaury Lacerda, D. Goyallon
Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability. The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations. The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project. This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.
{"title":"Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil","authors":"Hélio Alves Pedrosa, F. Colbert, F. Garcia, R. Gachet, Alberto Carlos Boldrini, Jose Marcio De Souza, Marcelo Oliveira Carrara, R. Okullo, Joan Hernandez Belisario, Ly Amaury Lacerda, D. Goyallon","doi":"10.2118/207370-ms","DOIUrl":"https://doi.org/10.2118/207370-ms","url":null,"abstract":"\u0000 Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability.\u0000 The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations.\u0000 The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available \"on call\" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project.\u0000 This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74513922","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. F. Fathalla, M. A. Al Hosani, I. Mohamed, A. A. Al Bairaq, Aditya Ojha, S. Mengal, Y. Pramudyo, R. Nachiappan, I. O. Bankole
This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells. The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.
{"title":"Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE","authors":"M. F. Fathalla, M. A. Al Hosani, I. Mohamed, A. A. Al Bairaq, Aditya Ojha, S. Mengal, Y. Pramudyo, R. Nachiappan, I. O. Bankole","doi":"10.2118/207313-ms","DOIUrl":"https://doi.org/10.2118/207313-ms","url":null,"abstract":"\u0000 This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells.\u0000 The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme\u0000 The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78662368","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}
Majda Jan Mohammad, Muneer Al Noumani, I. Cameron, Younis Al Masoudi
BP operates Khazzan & Ghazeer fields in the Sultanate of Oman with the aim to deliver safe, reliable and efficient wells. Efficiencies within drilling fluids design form part of a greater continuous improvement cycle to well delivery cost. With fluids spend contributing to a significant portion of the executed well cost (typically 15 % in Oman), fluids design changes hold the potential to yield positive cost savings (where well performance is maintained). This paper presents the areas of fluids design which were explored to reduce fluids spend as part of the continuous improvement cycle. Combined, the changes to fluids design evolved to reduce the fluids cost of Barik vertical wells to 6% of total well cost. All avenues of fluids design and the costs associated with the fluids operation in Oman were viewed as being in scope for change to maintain overbalance hydrostatic pressure on fluids spend. The methodology employed to reduce fluids spend can be described in four steps as per continuous improvement roadmaps; identify the cost saving project, the key enablers which allow the cost saving to be realized, risk/reward analysis where low risk/high reward projects were accelerated as priority and placed to the front of the queue for field trial and where a trial outcome is positive, the change is introduced permanently to the operation. This process worked well in continuously pushing fluid performance and reducing the fluids spend in Oman. The scope of change to fluids design was wide, with each ‘value adding project’ providing its own cumulative cost benefit. The projects which contributed to significantly reducing the overall fluids spend in Oman focused on personnel, fluid type selection, fluids formulation optimization, wellbore strengthening, fluid consumption and recycling, drilling fluids practice and brine selection. Reductions in fluids spend were accompanied with an improved well performance. Well delivery times being continuously observed to improve throughout the campaign (63 days vs 42 days). Whilst the fluids design is not directly responsible for this outcome, it does highlight that the changes made to fluids design positively influenced the improved well delivery performance. The drilling fluids optimization initiatives resulted in significant time and cost saving thus reduction in overall Barik vertical well drilling cost. Drilling fluids cost is reduced by over 55% without impact on safety and drilling performance.
{"title":"Block 61 Drilling Fluids Optimization Journey","authors":"Majda Jan Mohammad, Muneer Al Noumani, I. Cameron, Younis Al Masoudi","doi":"10.2118/207259-ms","DOIUrl":"https://doi.org/10.2118/207259-ms","url":null,"abstract":"\u0000 BP operates Khazzan & Ghazeer fields in the Sultanate of Oman with the aim to deliver safe, reliable and efficient wells. Efficiencies within drilling fluids design form part of a greater continuous improvement cycle to well delivery cost. With fluids spend contributing to a significant portion of the executed well cost (typically 15 % in Oman), fluids design changes hold the potential to yield positive cost savings (where well performance is maintained).\u0000 This paper presents the areas of fluids design which were explored to reduce fluids spend as part of the continuous improvement cycle. Combined, the changes to fluids design evolved to reduce the fluids cost of Barik vertical wells to 6% of total well cost.\u0000 All avenues of fluids design and the costs associated with the fluids operation in Oman were viewed as being in scope for change to maintain overbalance hydrostatic pressure on fluids spend.\u0000 The methodology employed to reduce fluids spend can be described in four steps as per continuous improvement roadmaps; identify the cost saving project, the key enablers which allow the cost saving to be realized, risk/reward analysis where low risk/high reward projects were accelerated as priority and placed to the front of the queue for field trial and where a trial outcome is positive, the change is introduced permanently to the operation. This process worked well in continuously pushing fluid performance and reducing the fluids spend in Oman.\u0000 The scope of change to fluids design was wide, with each ‘value adding project’ providing its own cumulative cost benefit. The projects which contributed to significantly reducing the overall fluids spend in Oman focused on personnel, fluid type selection, fluids formulation optimization, wellbore strengthening, fluid consumption and recycling, drilling fluids practice and brine selection.\u0000 Reductions in fluids spend were accompanied with an improved well performance. Well delivery times being continuously observed to improve throughout the campaign (63 days vs 42 days). Whilst the fluids design is not directly responsible for this outcome, it does highlight that the changes made to fluids design positively influenced the improved well delivery performance.\u0000 The drilling fluids optimization initiatives resulted in significant time and cost saving thus reduction in overall Barik vertical well drilling cost. Drilling fluids cost is reduced by over 55% without impact on safety and drilling performance.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72654125","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Dixit, P. Vasilyev, I. Mihaljević, M. Tham, D. Vígh, A. Zarkhidze, G. Cambois, M. Mahgoub
Full-waveform inversion (FWI) has become a well-established method for obtaining a detailed earth model suitable for improved imaging, near-surface characterization and pore-pressure prediction. FWI for onshore data has always been challenging and has seen limited application (Vigh et al, 2018). It requires a dedicated data processing approach related to the lower signal-to-noise ratio, accounting for variable topography and complex near-surface related effects. During the past few years, ADNOC has been acquiring and processing one of the world's largest combined 3D onshore and offshore seismic surveys in the Emirate of Abu Dhabi. The modern acquisition parameters that were implemented enabled the acquisition of broadband onshore seismic data rich in low frequencies that could benefit the initial stages of the FWI workflow. Sand dunes and sabkha layers at the surface, and high-velocity carbonate and dolomite layers in the subsurface pose a significant challenge for near-surface modeling in the UAE. The purpose of this work is to evaluate FWI application onshore UAE for near-surface characterization. We will compare the FWI results with conventional approaches for the near-surface model building that has been used routinely on land datasets in UAE, such as data-driven image-based statics (DIBS, Zarubov et al, 2019). One of the main challenges is data preconditioning, as onshore seismic data typically exhibits high levels of noise. It is imperative to denoise gathers sufficiently prior to the FWI process. A well sonic velocity function with large smoothing was used to build the starting velocity model for FWI. The process aims to minimize the least-squared difference between predicted and observed seismic responses by means of updating the model on which the prediction is based. As the predicted and seismic responses are functions of model parameters as well as source signature, a good estimate of the source wavelet is important for update and convergence in FWI. During this FWI work, source wavelet inversion was done as a separate step and used in subsequent FWI passes. FWI inversion started with adjustive FWI (Kun et al, 2015) on lower frequencies, moving to higher frequencies where both adjustive and least square objective functions were used. We will further show assessment of the anisotropy, initial conditions, usage of geological constraints, and comparisons to the conventional solutions. A comparison of results shows that FWI has successfully added velocity details to the near-surface model that follow the geological trend and conforms to well information while producing a plausible static solution. We have demonstrated the application of FWI onshore UAE for near-surface modeling. Although turnaround time (TAT) has increased compared to the conventional approach, the learning that was gained during this trial will decrease TAT for the future FWI work.
全波形反演(FWI)已成为一种获得详细地球模型的成熟方法，适用于改进成像、近地表表征和孔隙压力预测。陆上数据的FWI一直具有挑战性，并且应用有限(Vigh等人，2018)。它需要一种与较低信噪比相关的专用数据处理方法，考虑到多变的地形和复杂的近地表相关影响。在过去的几年中，ADNOC一直在阿布扎比酋长国收购和处理世界上最大的陆上和海上三维地震调查之一。采用现代采集参数，可以采集丰富的低频宽带陆上地震数据，有利于FWI工作流程的初始阶段。在阿联酋，地表的沙丘和sabkha层以及地下的高速碳酸盐和白云岩层对近地表建模构成了重大挑战。这项工作的目的是评估FWI在阿联酋陆上近地面的应用。我们将比较FWI结果与阿联酋陆地数据集常规使用的近地表模型构建的传统方法，如数据驱动的基于图像的静态(DIBS, Zarubov等，2019)。其中一个主要的挑战是数据预处理，因为陆上地震数据通常显示出高水平的噪声。在FWI处理之前，必须对采集信号进行充分的降噪。采用平滑度较大的声速函数建立了FWI启动速度模型。该过程旨在通过更新预测所依据的模型，使预测和观测地震反应之间的最小二乘差最小化。由于预测响应和地震响应是模型参数和震源特征的函数，因此良好的震源小波估计对FWI的更新和收敛具有重要意义。在FWI工作中，源小波反演作为一个单独的步骤进行，并用于后续的FWI工作。FWI反演从较低频率的可调FWI (Kun et al .， 2015)开始，移动到使用可调和最小二乘目标函数的较高频率。我们将进一步展示各向异性的评估、初始条件、地质约束的使用，以及与常规解决方案的比较。对比结果表明，FWI成功地将速度细节添加到近地表模型中，该模型遵循地质趋势，符合井信息，同时产生了合理的静态解决方案。我们已经展示了FWI在阿联酋陆上近地面建模中的应用。虽然与传统方法相比，周转时间(TAT)增加了，但在本次试验中获得的经验将减少未来FWI工作的TAT。
{"title":"Full Waveform Inversion for the Near Surface Characterization, Onshore UAE, Case Study","authors":"R. Dixit, P. Vasilyev, I. Mihaljević, M. Tham, D. Vígh, A. Zarkhidze, G. Cambois, M. Mahgoub","doi":"10.2118/207492-ms","DOIUrl":"https://doi.org/10.2118/207492-ms","url":null,"abstract":"\u0000 Full-waveform inversion (FWI) has become a well-established method for obtaining a detailed earth model suitable for improved imaging, near-surface characterization and pore-pressure prediction. FWI for onshore data has always been challenging and has seen limited application (Vigh et al, 2018). It requires a dedicated data processing approach related to the lower signal-to-noise ratio, accounting for variable topography and complex near-surface related effects.\u0000 During the past few years, ADNOC has been acquiring and processing one of the world's largest combined 3D onshore and offshore seismic surveys in the Emirate of Abu Dhabi. The modern acquisition parameters that were implemented enabled the acquisition of broadband onshore seismic data rich in low frequencies that could benefit the initial stages of the FWI workflow.\u0000 Sand dunes and sabkha layers at the surface, and high-velocity carbonate and dolomite layers in the subsurface pose a significant challenge for near-surface modeling in the UAE. The purpose of this work is to evaluate FWI application onshore UAE for near-surface characterization. We will compare the FWI results with conventional approaches for the near-surface model building that has been used routinely on land datasets in UAE, such as data-driven image-based statics (DIBS, Zarubov et al, 2019).\u0000 One of the main challenges is data preconditioning, as onshore seismic data typically exhibits high levels of noise. It is imperative to denoise gathers sufficiently prior to the FWI process. A well sonic velocity function with large smoothing was used to build the starting velocity model for FWI. The process aims to minimize the least-squared difference between predicted and observed seismic responses by means of updating the model on which the prediction is based. As the predicted and seismic responses are functions of model parameters as well as source signature, a good estimate of the source wavelet is important for update and convergence in FWI. During this FWI work, source wavelet inversion was done as a separate step and used in subsequent FWI passes.\u0000 FWI inversion started with adjustive FWI (Kun et al, 2015) on lower frequencies, moving to higher frequencies where both adjustive and least square objective functions were used. We will further show assessment of the anisotropy, initial conditions, usage of geological constraints, and comparisons to the conventional solutions. A comparison of results shows that FWI has successfully added velocity details to the near-surface model that follow the geological trend and conforms to well information while producing a plausible static solution.\u0000 We have demonstrated the application of FWI onshore UAE for near-surface modeling. Although turnaround time (TAT) has increased compared to the conventional approach, the learning that was gained during this trial will decrease TAT for the future FWI work.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77419602","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}
H. Gupta, Beth Farmer, S. Large, Majda Balushi, Laila Saadi, K. Kumar, Carlos Alberto Moreno, Mohammed Ruqaishi, Yusra Busaidi, H. Hillgartner, B. Agarwal, S. Abri
In recent years, with the steep drop and increased volatility in oil price, there is an urgency for making our field (re-development) plans more dynamic and efficient with faster payback and with particular emphasis on robustness against uncertainties. This paper describes a root cause analysis and a methodology to achieve up to ~30% improvement in field development planning project cycle and developing a better-integrated reservoir understanding. A comprehensive integrated analysis of available data is a key success criterion for robust decision-making. A detailed value stream mapping and a timeline analysis for data analysis in the hydrocarbon maturation process revealed that our process cycle efficiency is only 16% with a significant room for improvement. Any improvement can be directly translated to man-hour cost saving and acceleration of oil delivery. Effective use of technology and digitalization for knowledge management, standardized ways of working and easy access to historical data, analysis and diagnostics were identified as key focus areas to improve delivery. An innovative process and web based digital platform, iResDAT, is developed for accelerating data analysis. It mines from volumes of petro-technical databases and translates data into standardized diagnostics using latest data analytics and visualization technologies. It has already reduced dramatically the time to mine critical subsurface data and prepare required integrated diagnostics that are auditable and can be re-created in a few seconds. Based on the early pilot studies the cycle time reduction in the data analysis phase is close to 30% with improved quality and standardization of the integrated analysis. It has already transformed the ways of working where the subsurface discussion can happen across disciplines using a single platform that enforces early integration for reservoir understanding and associated uncertainty characterization. It is a web-based platform where the diagnostic dashboards are crowd sourced; sustained and enhanced by the business to ensure the relevance and sustainability with the Corporate Data Management and IT functions. It is a building block towards quality controlled and auditable data analysis and interpreted dataset, which may form the backbone for any advanced analytics in future to enable digitally enabled hydrocarbon maturation.
{"title":"Accelerating Hydrocarbon Maturation and Project Delivery by 30% with Digitalization - Standardizing on the Fly Analysis to Enable Informed Decision Making Using Petabytes of Petro Technical Data","authors":"H. Gupta, Beth Farmer, S. Large, Majda Balushi, Laila Saadi, K. Kumar, Carlos Alberto Moreno, Mohammed Ruqaishi, Yusra Busaidi, H. Hillgartner, B. Agarwal, S. Abri","doi":"10.2118/207711-ms","DOIUrl":"https://doi.org/10.2118/207711-ms","url":null,"abstract":"\u0000 In recent years, with the steep drop and increased volatility in oil price, there is an urgency for making our field (re-development) plans more dynamic and efficient with faster payback and with particular emphasis on robustness against uncertainties. This paper describes a root cause analysis and a methodology to achieve up to ~30% improvement in field development planning project cycle and developing a better-integrated reservoir understanding.\u0000 A comprehensive integrated analysis of available data is a key success criterion for robust decision-making. A detailed value stream mapping and a timeline analysis for data analysis in the hydrocarbon maturation process revealed that our process cycle efficiency is only 16% with a significant room for improvement. Any improvement can be directly translated to man-hour cost saving and acceleration of oil delivery. Effective use of technology and digitalization for knowledge management, standardized ways of working and easy access to historical data, analysis and diagnostics were identified as key focus areas to improve delivery.\u0000 An innovative process and web based digital platform, iResDAT, is developed for accelerating data analysis. It mines from volumes of petro-technical databases and translates data into standardized diagnostics using latest data analytics and visualization technologies. It has already reduced dramatically the time to mine critical subsurface data and prepare required integrated diagnostics that are auditable and can be re-created in a few seconds. Based on the early pilot studies the cycle time reduction in the data analysis phase is close to 30% with improved quality and standardization of the integrated analysis.\u0000 It has already transformed the ways of working where the subsurface discussion can happen across disciplines using a single platform that enforces early integration for reservoir understanding and associated uncertainty characterization. It is a web-based platform where the diagnostic dashboards are crowd sourced; sustained and enhanced by the business to ensure the relevance and sustainability with the Corporate Data Management and IT functions. It is a building block towards quality controlled and auditable data analysis and interpreted dataset, which may form the backbone for any advanced analytics in future to enable digitally enabled hydrocarbon maturation.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79782933","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}
Mahmoud AbdulHameed Al Mahmoud, Joseph Sylvester Pius David, Askar Jaffer
Alarm Management Systems ("AMS") have been adopted in the oil & gas industry where several benefits were realized. Such as improved panel operator effectiveness, maintaining higher levels of plant uptime and integrity, reducing the number of abnormal situation. Which ultimately leads to higher asset productivity. Several OPCO have multiple operational assets/sites that are geographically diverse. Where each asset might have a different Integrated Control System ("ICS") due to the time and availability of technology at the time of commissioning. Requiring diverse locally implemented AMS. A unified CAMS thus reduces time and effort to develop, deploy, and maintain alarm systems and is an essential toolkit for enhanced safe operation of the plant. Some sites have multiple plants wuth common pocess control section. The process control enginners needs to visit individual plants access DCS alalrms. By carryinhour corporate alarm management, engibbers at their office PCs have the access to the DCS alarms. Implementing CAMS requires the presence of a robust data presence infrastructure in place. Notably a centralized plant information management system, where several real time data points with regards to alarms and operator inputs can be captured. A CAMS unifies the approach of how alarm management is conducted in the company. Where a CAMS system generates a set of standard and custom templates that highlight the performance of each operating asset/shift/panel operator. Providing insights into the performance of each asset, efficiency of each operational shift and response of the panel operators. That when addressed, will lead to an overall performance and production of the operational asset. With this alarm management data, it can be further enhanced through data analytics to identify areas where operational efficiencies can be achieved. Additionally, the CAMS reduces the times and effort to deploy an alarm management system for any future operating asset expansions. CAMS coupled with real time data and Machine learning algorithms, past behaviours of the plant can be correlated, which can then be utilised for future predictions on alarms. This would further enhance our data driven decision-making, and would reduce the dependence on personal driven decisions. It can be concluded, that the CAMS is worthy investment for operating companies that have geographical/ICS diverse operational assets.
{"title":"Achieving Operational Efficiencies from a Centralized Alarm Management System","authors":"Mahmoud AbdulHameed Al Mahmoud, Joseph Sylvester Pius David, Askar Jaffer","doi":"10.2118/208034-ms","DOIUrl":"https://doi.org/10.2118/208034-ms","url":null,"abstract":"\u0000 Alarm Management Systems (\"AMS\") have been adopted in the oil & gas industry where several benefits were realized. Such as improved panel operator effectiveness, maintaining higher levels of plant uptime and integrity, reducing the number of abnormal situation. Which ultimately leads to higher asset productivity.\u0000 Several OPCO have multiple operational assets/sites that are geographically diverse. Where each asset might have a different Integrated Control System (\"ICS\") due to the time and availability of technology at the time of commissioning. Requiring diverse locally implemented AMS.\u0000 A unified CAMS thus reduces time and effort to develop, deploy, and maintain alarm systems and is an essential toolkit for enhanced safe operation of the plant.\u0000 Some sites have multiple plants wuth common pocess control section. The process control enginners needs to visit individual plants access DCS alalrms. By carryinhour corporate alarm management, engibbers at their office PCs have the access to the DCS alarms.\u0000 Implementing CAMS requires the presence of a robust data presence infrastructure in place. Notably a centralized plant information management system, where several real time data points with regards to alarms and operator inputs can be captured.\u0000 A CAMS unifies the approach of how alarm management is conducted in the company. Where a CAMS system generates a set of standard and custom templates that highlight the performance of each operating asset/shift/panel operator. Providing insights into the performance of each asset, efficiency of each operational shift and response of the panel operators. That when addressed, will lead to an overall performance and production of the operational asset.\u0000 With this alarm management data, it can be further enhanced through data analytics to identify areas where operational efficiencies can be achieved. Additionally, the CAMS reduces the times and effort to deploy an alarm management system for any future operating asset expansions.\u0000 CAMS coupled with real time data and Machine learning algorithms, past behaviours of the plant can be correlated, which can then be utilised for future predictions on alarms. This would further enhance our data driven decision-making, and would reduce the dependence on personal driven decisions.\u0000 It can be concluded, that the CAMS is worthy investment for operating companies that have geographical/ICS diverse operational assets.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79072897","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}
Arjun Roy, Senthilkumar Datchanamoorthy, Sangeeta Nundy, Bhaskerrao Keely, Okja Kim, Godine Chan
Metal-oxide based emission detection sensors are typically used for point measurements of hydrocarbon emissions. They are low-cost sensors and can be used for continuous monitoring of emissions. This paper describes an analytical framework that uses time series data from a collection of such sensors deployed at a customer site, along with weather conditions, to detect anomalies in emission data, identify possible emission sources and estimate the leak rate from fugitive emissions. The analytical framework also comprises an optimization module that helps in determining the optimal number of sensors required and their potential location at a customer site. The paper discusses results of the different steps in the analytical framework obtained using concentration data generated using numerical simulations and obtained through controlled leak field tests.
{"title":"Fugitive Emission Monitoring System Using Land-Based Sensors for Industrial Applications","authors":"Arjun Roy, Senthilkumar Datchanamoorthy, Sangeeta Nundy, Bhaskerrao Keely, Okja Kim, Godine Chan","doi":"10.2118/207822-ms","DOIUrl":"https://doi.org/10.2118/207822-ms","url":null,"abstract":"\u0000 Metal-oxide based emission detection sensors are typically used for point measurements of hydrocarbon emissions. They are low-cost sensors and can be used for continuous monitoring of emissions. This paper describes an analytical framework that uses time series data from a collection of such sensors deployed at a customer site, along with weather conditions, to detect anomalies in emission data, identify possible emission sources and estimate the leak rate from fugitive emissions. The analytical framework also comprises an optimization module that helps in determining the optimal number of sensors required and their potential location at a customer site. The paper discusses results of the different steps in the analytical framework obtained using concentration data generated using numerical simulations and obtained through controlled leak field tests.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85235083","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}
Understanding the earth's subsurface is critical to the needs of the exploration and production (E&P) industry for minimizing risk and maximizing recovery. Until recently, the industry's service sector has not made many advances in data-driven automated earth model building from raw exploration seismic data. But thankfully, that has now changed. The industry's leading technique to gain an unprecedented increase in resolution and accuracy when establishing a view of the interior of the earth is known as the Full Waveform Inversion (FWI). Advanced formulations of FWI are capable of automating subsurface model building using only raw unprocessed data. Cloud-based FWI is helping to accelerate this journey by encompassing the most sophisticated waveform inversion techniques with the largest compute facility on the planet. This combines to give verifiable accuracy, more automation and more efficiency. In this paper, we describe the transformation of enabling cloud-based FWI to natively take advantage of the public cloud platform's main strength in terms of flexibility and on-demand scalability. We start from lift-and-shift of a legacy MPI-based application designed to be run by a traditional on-prem job scheduler. Our specific goals are to (1) utilize a heterogeneous set of compute hardware throughout the lifecycle of a production FWI run without having to provision them for the entire duration, (2) take advantage of cost-efficient spare-capacity compute instances without uptime guarantees, and (3) maintain a single codebase that can be run both on on-prem HPC systems and on the cloud. To achieve these goals meant transitioning the job-scheduling and "embarrassingly parallel" aspects of the communication code away from using MPI, and onto various cloud-based orchestration systems, as well as finding cloud-based solutions that worked and scaled well for the broadcast/reduction operation. Placing these systems behind a customized TCP-based stub for MPI library calls allows us to run the code as-is in an on-prem HPC environment, while on the cloud we can asynchronously provision and suspend worker instances (potentially with very different hardware configurations) as needed without the burden of maintaining a static MPI world communicator. With this dynamic cloud-native architecture, we 1) utilize advanced formulations of FWI capable of automating subsurface model building using only raw unprocessed data, 2) extract velocity models from the full recorded wavefield (refractions, reflections and multiples), and 3) introduce explicit sensitivity to reflection moveout, invisible to conventional FWI, for macro-model updates below the diving wave zone. This makes it viable to go back to older legacy datasets acquired in complex environments and unlock considerable value where FWI until now has been impossible to apply successfully from a poor starting model.
{"title":"Accelerating Subsurface Data Processing and Interpretation with Cloud-Based Full Waveform Inversion Systems","authors":"Sirivan Chaleunxay, N. Shah","doi":"10.2118/207744-ms","DOIUrl":"https://doi.org/10.2118/207744-ms","url":null,"abstract":"\u0000 Understanding the earth's subsurface is critical to the needs of the exploration and production (E&P) industry for minimizing risk and maximizing recovery. Until recently, the industry's service sector has not made many advances in data-driven automated earth model building from raw exploration seismic data. But thankfully, that has now changed. The industry's leading technique to gain an unprecedented increase in resolution and accuracy when establishing a view of the interior of the earth is known as the Full Waveform Inversion (FWI). Advanced formulations of FWI are capable of automating subsurface model building using only raw unprocessed data.\u0000 Cloud-based FWI is helping to accelerate this journey by encompassing the most sophisticated waveform inversion techniques with the largest compute facility on the planet. This combines to give verifiable accuracy, more automation and more efficiency. In this paper, we describe the transformation of enabling cloud-based FWI to natively take advantage of the public cloud platform's main strength in terms of flexibility and on-demand scalability. We start from lift-and-shift of a legacy MPI-based application designed to be run by a traditional on-prem job scheduler.\u0000 Our specific goals are to (1) utilize a heterogeneous set of compute hardware throughout the lifecycle of a production FWI run without having to provision them for the entire duration, (2) take advantage of cost-efficient spare-capacity compute instances without uptime guarantees, and (3) maintain a single codebase that can be run both on on-prem HPC systems and on the cloud. To achieve these goals meant transitioning the job-scheduling and \"embarrassingly parallel\" aspects of the communication code away from using MPI, and onto various cloud-based orchestration systems, as well as finding cloud-based solutions that worked and scaled well for the broadcast/reduction operation. Placing these systems behind a customized TCP-based stub for MPI library calls allows us to run the code as-is in an on-prem HPC environment, while on the cloud we can asynchronously provision and suspend worker instances (potentially with very different hardware configurations) as needed without the burden of maintaining a static MPI world communicator.\u0000 With this dynamic cloud-native architecture, we 1) utilize advanced formulations of FWI capable of automating subsurface model building using only raw unprocessed data, 2) extract velocity models from the full recorded wavefield (refractions, reflections and multiples), and 3) introduce explicit sensitivity to reflection moveout, invisible to conventional FWI, for macro-model updates below the diving wave zone. This makes it viable to go back to older legacy datasets acquired in complex environments and unlock considerable value where FWI until now has been impossible to apply successfully from a poor starting model.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85702855","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}
Vuong Van Pham, Amirmasoud Kalantari Dahaghi, S. Negahban, W. Fincham, A. Babakhani
Unconventional oil and gas reservoir development requires an understanding of the geometry and complexity of hydraulic fractures. The current categories of fracture diagnostic approaches include methods for near-wellbore (production and temperature logs, tracers, borehole imaging) and far-field techniques (micro-seismic fracture mapping). These techniques provide an indirect and/or interpreted fracture geometry. Therefore, none of these methods consistently provides a fully detailed and accurate description of the character of created hydraulic fractures. This study proposes a novel approach that uses direct data from the injected fine size and battery-less Smart MicroChip Proppants (SMPs) to map the fracture geometry. This novel approach enables direct, fast, and smart of the received high-resolution geo-sensor data from the SMPs collected in high pressure and high-temperature environment and maps the fracture network using the proposed Intelligent and Integrated Fracture Diagnostic Platform (IFDP), which is a closed-loop architecture and is based on multi-dimensional projection, unsupervised clustering, and surface reconstruction. Affine transformation and a shallow ANN are integrated to control the stochasticity of clustering. IFDP proves its efficacy in fracture diagnostics for 3 in-house design synthetic fracture networks, with 100% consistency, rated "fairly satisfied" to "highly satisfied" in prediction capability, and between 85-100% in execution robustness. The integration of the couple affine transformation-ANN increases the performance of unsupervised clustering in IFDP.
{"title":"Intelligent Fracture Diagnostic Procedure Using Smart Microchip Proppants Data","authors":"Vuong Van Pham, Amirmasoud Kalantari Dahaghi, S. Negahban, W. Fincham, A. Babakhani","doi":"10.2118/208195-ms","DOIUrl":"https://doi.org/10.2118/208195-ms","url":null,"abstract":"\u0000 Unconventional oil and gas reservoir development requires an understanding of the geometry and complexity of hydraulic fractures. The current categories of fracture diagnostic approaches include methods for near-wellbore (production and temperature logs, tracers, borehole imaging) and far-field techniques (micro-seismic fracture mapping). These techniques provide an indirect and/or interpreted fracture geometry. Therefore, none of these methods consistently provides a fully detailed and accurate description of the character of created hydraulic fractures. This study proposes a novel approach that uses direct data from the injected fine size and battery-less Smart MicroChip Proppants (SMPs) to map the fracture geometry. This novel approach enables direct, fast, and smart of the received high-resolution geo-sensor data from the SMPs collected in high pressure and high-temperature environment and maps the fracture network using the proposed Intelligent and Integrated Fracture Diagnostic Platform (IFDP), which is a closed-loop architecture and is based on multi-dimensional projection, unsupervised clustering, and surface reconstruction. Affine transformation and a shallow ANN are integrated to control the stochasticity of clustering. IFDP proves its efficacy in fracture diagnostics for 3 in-house design synthetic fracture networks, with 100% consistency, rated \"fairly satisfied\" to \"highly satisfied\" in prediction capability, and between 85-100% in execution robustness. The integration of the couple affine transformation-ANN increases the performance of unsupervised clustering in IFDP.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82518753","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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