Well Performance can deteriorate due to several reasons, for example: formation damage, scale buildup, back pressure from other wells, artificial lift issue etc. In this paper we present an application of utilizing machine learning to build a model to articulate and flag deterioration and reason behind it. The model was used to flag problems such as salt and scale build up in the tubing as well as backpressure due to emulsions in the tubing or in topside pipes. The model was capable of monitoring well performance using only the well head parameters
{"title":"Autonomous Well Performance Troubleshooting; A Promising Data-Driven Application","authors":"Sherif Abdelrahman, Mohamed Al-Ajmi, T. Essam","doi":"10.2523/iptc-22398-ms","DOIUrl":"https://doi.org/10.2523/iptc-22398-ms","url":null,"abstract":"\u0000 Well Performance can deteriorate due to several reasons, for example: formation damage, scale buildup, back pressure from other wells, artificial lift issue etc. In this paper we present an application of utilizing machine learning to build a model to articulate and flag deterioration and reason behind it. The model was used to flag problems such as salt and scale build up in the tubing as well as backpressure due to emulsions in the tubing or in topside pipes. The model was capable of monitoring well performance using only the well head parameters","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85670768","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}
Ming Xue, Xingchun Li, Xiangyu Cui, Qi Wang, Shuangxing Liu, J. Zheng, Yilin Wang
As one of the largest emitters in the world, the oil and gas industry needs more efforts on greenhouse gas reduction. Methane, as a potent greenhouse gas, could largely determine whether natural gas could serve as a bridging energy towards a sustainable future. In the past decade, the oil and gas companies in China has significantly enhanced casing gas recovery and reduced large volume of flaring (>20k m3/day). However, the remaining low- to mid- volume flaring gas were left for further recovery. Shale gas production in China has met a surge in the number of drilling wells. Those new wells were characterized by a relatively low gas production rate (<1 mill m3/day), in comparison with the shale gas well in the US. As a result, flaring gas during well completion needs to be recycled or used so as to enhance the gas recovery rate. In this study, a pilot demonstration project of flaring gas recovery was carried out to reduce greenhouse gas emission in Weiyuan shale gas region in Sichuan province, China. The technical route of dehydration and natural gas compression was adopted. The recycled natural gas was transformed into compressed natural gas (CNG) and transported to the nearest CNG station for further use. The inlet gas pressure were between 2.85 to 5.82 MPa and the outlet pressure were kept stable around 20 MPa to meet the standard of CNG. The minimum dew point temperature was -65.5 °C and the outlet temperature rise remained below 23 °C. The manufactured device also showed a sound flexibility with recover rate between 523.22 to 1224.38 m3/h, which was the 28% to 157% of the designed capacity. An overall of 21k of natural gas was recoverd. For a single well completion event, a total of 50k of natural gas could be recovered by this device. The device applied in the pilot demonstration has well matched with the local transportation, gas composition, and surface engineering of the well completion and has the potential of popularization and application in the shale gas region in Sichuan. In that case, it could reach a future economic return over 0.6 billion RMB.
{"title":"A Pilot Demonstration of Flaring Gas Recovery During Shale Gas Well Completion in China","authors":"Ming Xue, Xingchun Li, Xiangyu Cui, Qi Wang, Shuangxing Liu, J. Zheng, Yilin Wang","doi":"10.2523/iptc-22290-ms","DOIUrl":"https://doi.org/10.2523/iptc-22290-ms","url":null,"abstract":"\u0000 \u0000 \u0000 As one of the largest emitters in the world, the oil and gas industry needs more efforts on greenhouse gas reduction. Methane, as a potent greenhouse gas, could largely determine whether natural gas could serve as a bridging energy towards a sustainable future. In the past decade, the oil and gas companies in China has significantly enhanced casing gas recovery and reduced large volume of flaring (>20k m3/day). However, the remaining low- to mid- volume flaring gas were left for further recovery.\u0000 \u0000 \u0000 \u0000 Shale gas production in China has met a surge in the number of drilling wells. Those new wells were characterized by a relatively low gas production rate (<1 mill m3/day), in comparison with the shale gas well in the US. As a result, flaring gas during well completion needs to be recycled or used so as to enhance the gas recovery rate. In this study, a pilot demonstration project of flaring gas recovery was carried out to reduce greenhouse gas emission in Weiyuan shale gas region in Sichuan province, China. The technical route of dehydration and natural gas compression was adopted. The recycled natural gas was transformed into compressed natural gas (CNG) and transported to the nearest CNG station for further use.\u0000 \u0000 \u0000 \u0000 The inlet gas pressure were between 2.85 to 5.82 MPa and the outlet pressure were kept stable around 20 MPa to meet the standard of CNG. The minimum dew point temperature was -65.5 °C and the outlet temperature rise remained below 23 °C. The manufactured device also showed a sound flexibility with recover rate between 523.22 to 1224.38 m3/h, which was the 28% to 157% of the designed capacity. An overall of 21k of natural gas was recoverd.\u0000 \u0000 \u0000 \u0000 For a single well completion event, a total of 50k of natural gas could be recovered by this device. The device applied in the pilot demonstration has well matched with the local transportation, gas composition, and surface engineering of the well completion and has the potential of popularization and application in the shale gas region in Sichuan. In that case, it could reach a future economic return over 0.6 billion RMB.\u0000","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89578291","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}
X. Zhuang, Wendong Wang, Renfeng Yang, Yuan Li, Menghe Shi, Yuliang Su, Ibrahim Albouzedy
The efficient development of oilfield mostly depends on a comprehensive optimization of subsurface flow. The development effect of water-flooding is affected by technology, economy and other aspects, so its development objective is not invariable. To account for several discrete or even contradicting objectives, dynamic multi-objective optimization evolutionary algorithm (DMOEA) presents multiple optimum solutions for decision-making processes. The primary goal of this work is to optimize well placement and control parameters based on multiple design objectives using reservoir production potential formula and surrogate-assisted dynamic multi-objective optimization evolutionary algorithm. A new workflow is introduced to optimize water-flooding strategy in presence of multiple conflicting criteria and time-depending constraints. The workflow consists of two optimization stages. First, we construct an improved reservoir production potential formula which considers factors such as oil saturation, pressure, fluid flow capacity, etc. The influence of dynamic seepage capacity and static reserve distribution of oil on reservoir production capacity is comprehensively evaluated by this formula. Optimal well placement can be guided based on production potential. Then, a robust computational framework that couples Deep Neural Network (DNN) and dynamic multi-objective optimizers to optimize the aforementioned objectives in water-flooding processes simultaneously. DNN is trained and employed as surrogate model of the high-fidelity simulator in the optimization workflow and DNSGA-II-A is employed to optimize control parameters by maximizing the overall oil production and NPV, and minimizing the water cut. The Pareto front arising from the above process provides many water-flooding scenarios yielding to practical decision-making capabilities. The performance of the proposed workflow is validated in Shengli Oilfield. The results demonstrate that the method can ensure the more reasonable optimization of the whole process of water-flooding. This work can provide not only the economic and technical solutions but the correct optimization responses according to the multiple design objectives. Besides, the robustness and convergence speed of this method is better than other algorithms. Compared with the traditional single-objective optimization algorithm, the proposed method can comprehensively consider the relationship between various development objectives, to give reasonable optimal solutions. Compared with the traditional static optimization algorithm, it can track the changing Pareto optimal front in time, to provide a diversified optimal solution set according to the needs of reservoir engineers. The major contribution of this work is the introduction of a new approach that can effectively balance the needs of various objectives such as benefit, cost, and risk in the life-cycle of water-flooding and make a rapid response. The presented reliable method could
{"title":"An Efficient Methodology for Dynamic Multi-Objective Optimization of Water-Flooding Strategy","authors":"X. Zhuang, Wendong Wang, Renfeng Yang, Yuan Li, Menghe Shi, Yuliang Su, Ibrahim Albouzedy","doi":"10.2523/iptc-22027-ms","DOIUrl":"https://doi.org/10.2523/iptc-22027-ms","url":null,"abstract":"\u0000 The efficient development of oilfield mostly depends on a comprehensive optimization of subsurface flow. The development effect of water-flooding is affected by technology, economy and other aspects, so its development objective is not invariable. To account for several discrete or even contradicting objectives, dynamic multi-objective optimization evolutionary algorithm (DMOEA) presents multiple optimum solutions for decision-making processes. The primary goal of this work is to optimize well placement and control parameters based on multiple design objectives using reservoir production potential formula and surrogate-assisted dynamic multi-objective optimization evolutionary algorithm.\u0000 A new workflow is introduced to optimize water-flooding strategy in presence of multiple conflicting criteria and time-depending constraints. The workflow consists of two optimization stages. First, we construct an improved reservoir production potential formula which considers factors such as oil saturation, pressure, fluid flow capacity, etc. The influence of dynamic seepage capacity and static reserve distribution of oil on reservoir production capacity is comprehensively evaluated by this formula. Optimal well placement can be guided based on production potential. Then, a robust computational framework that couples Deep Neural Network (DNN) and dynamic multi-objective optimizers to optimize the aforementioned objectives in water-flooding processes simultaneously. DNN is trained and employed as surrogate model of the high-fidelity simulator in the optimization workflow and DNSGA-II-A is employed to optimize control parameters by maximizing the overall oil production and NPV, and minimizing the water cut. The Pareto front arising from the above process provides many water-flooding scenarios yielding to practical decision-making capabilities. The performance of the proposed workflow is validated in Shengli Oilfield. The results demonstrate that the method can ensure the more reasonable optimization of the whole process of water-flooding.\u0000 This work can provide not only the economic and technical solutions but the correct optimization responses according to the multiple design objectives. Besides, the robustness and convergence speed of this method is better than other algorithms. Compared with the traditional single-objective optimization algorithm, the proposed method can comprehensively consider the relationship between various development objectives, to give reasonable optimal solutions. Compared with the traditional static optimization algorithm, it can track the changing Pareto optimal front in time, to provide a diversified optimal solution set according to the needs of reservoir engineers.\u0000 The major contribution of this work is the introduction of a new approach that can effectively balance the needs of various objectives such as benefit, cost, and risk in the life-cycle of water-flooding and make a rapid response. The presented reliable method could ","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74463196","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}
Fabián Florez, D. Calderón, Gayatri P. Kartoatmodjo, Andrew Fendt, Gregor Wilson
Many IOC and NOC organizations have and continue to be face with the challenge of establishing a corporate standard for measuring production performance across their producing assets. The difficulty with this challgenge comes from reporting localized production, managing production shortfalls, and identifying opportunities to increase production. These are three critical elements of production excellence or production performance programs. This paper presents a solution for this challenge. This novel solution uses the choke model or limit diagram to integrate existing portions of the production performance framework; i. e., shortfall production management, opportunity identification workshops, and well potential calculations. The challenge is to duplicate these elements in a standard way across 12 active producing assets at different geographical locations, with diverse operating cultures, hydrocarbon types, contractual frameworks, and engineering criteria. Within three years all assets were sharing the same basis for Production Excellence program (Px) with strict reporting discipling enabled by common corporate system. During the same period the overall production efficiency increase by 3% adding 1.1 MMBOE into the tanks. In addition to the production baseline sustainability, other major benefits included the standardization of oil production loss classification and production opportunities identification workshop to keep the discipline of identifying production potential to reflect the everchanging field conditions. This paper will present the integration of the Px program as the main endevoar to make it a portion of the operating culture and the proposed method to capture and share the performance gains. Additionally, a tremendous effort was made to build some of the elements directly into the production data management systems in the local operating assets to enable the corporate reporting system to read any source of data. These data are then used as a business intelligence application reporting accessible via smart and interactive dashboards.
{"title":"Production Excellence Program Enhances Operation Efficiency","authors":"Fabián Florez, D. Calderón, Gayatri P. Kartoatmodjo, Andrew Fendt, Gregor Wilson","doi":"10.2523/iptc-22523-ms","DOIUrl":"https://doi.org/10.2523/iptc-22523-ms","url":null,"abstract":"\u0000 Many IOC and NOC organizations have and continue to be face with the challenge of establishing a corporate standard for measuring production performance across their producing assets. The difficulty with this challgenge comes from reporting localized production, managing production shortfalls, and identifying opportunities to increase production. These are three critical elements of production excellence or production performance programs.\u0000 This paper presents a solution for this challenge. This novel solution uses the choke model or limit diagram to integrate existing portions of the production performance framework; i. e., shortfall production management, opportunity identification workshops, and well potential calculations. The challenge is to duplicate these elements in a standard way across 12 active producing assets at different geographical locations, with diverse operating cultures, hydrocarbon types, contractual frameworks, and engineering criteria.\u0000 Within three years all assets were sharing the same basis for Production Excellence program (Px) with strict reporting discipling enabled by common corporate system. During the same period the overall production efficiency increase by 3% adding 1.1 MMBOE into the tanks.\u0000 In addition to the production baseline sustainability, other major benefits included the standardization of oil production loss classification and production opportunities identification workshop to keep the discipline of identifying production potential to reflect the everchanging field conditions.\u0000 This paper will present the integration of the Px program as the main endevoar to make it a portion of the operating culture and the proposed method to capture and share the performance gains. Additionally, a tremendous effort was made to build some of the elements directly into the production data management systems in the local operating assets to enable the corporate reporting system to read any source of data. These data are then used as a business intelligence application reporting accessible via smart and interactive dashboards.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74658551","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}
Yanhui Zhang, Hongyou Zhang, Ying-xian Liu, Shaomeng Wang, Chengcheng Wang
Because of the long horizontal length and the reservoir heterogeneity, the water production and injection are different along different locations of a horizontal well. So the conventional water injection string are not suitable for horizontal wells. Besides, the conventional models for inferring interwell connectivity between directional wells are not suitable for horizontal wells. In this paper, a new model for inferring interwell connectivity between horizontal wells is built and a new water injection string for horizontal injector is presented which can meet the demand of water injection of different locations for a horizontal well. Based on the conventional water injection string, a new packer was installed at water injection string with the location's deviation less than 60 degrees. A Water distributor working cylinder was installed to respectively distribute water to root and toe of a horizontal well. Inorder to characterize different sections of a horizontal well, a horizontal well can be considered as several directional wells with different physical properties such as permeability and porosity and so on. Based on this, the reservoir is characterized as a coarse model consisting of a number of interwell units which is controlled by any two directional wells. Injection and production data were used to infer interwell connectivity and geological characteristics. The results obtained from the new proposed model are in consistent with the oxygen activation of injectors. Interwell connectivity coefficient of each injector were calculated and the preponderance flow paths were found. Based on this, profile control were conducted. After profile control, the water injection efficiency of horizontal injectors obtained by this model improved and water cut of produces was reduced by 9% ~ 10%. This technique has been used in nearly 100 wells of Bohai oilfields. With the inter-well connectivity method and the balanced injection string for horizontal wells, the development effect of reservoir with horizontal wells improved significantly.
{"title":"Balanced Injection and Production Technique for Horizontal Wells Based on Inter-Well Connectivity","authors":"Yanhui Zhang, Hongyou Zhang, Ying-xian Liu, Shaomeng Wang, Chengcheng Wang","doi":"10.2523/iptc-22452-ms","DOIUrl":"https://doi.org/10.2523/iptc-22452-ms","url":null,"abstract":"\u0000 Because of the long horizontal length and the reservoir heterogeneity, the water production and injection are different along different locations of a horizontal well. So the conventional water injection string are not suitable for horizontal wells. Besides, the conventional models for inferring interwell connectivity between directional wells are not suitable for horizontal wells. In this paper, a new model for inferring interwell connectivity between horizontal wells is built and a new water injection string for horizontal injector is presented which can meet the demand of water injection of different locations for a horizontal well.\u0000 Based on the conventional water injection string, a new packer was installed at water injection string with the location's deviation less than 60 degrees. A Water distributor working cylinder was installed to respectively distribute water to root and toe of a horizontal well. Inorder to characterize different sections of a horizontal well, a horizontal well can be considered as several directional wells with different physical properties such as permeability and porosity and so on. Based on this, the reservoir is characterized as a coarse model consisting of a number of interwell units which is controlled by any two directional wells. Injection and production data were used to infer interwell connectivity and geological characteristics.\u0000 The results obtained from the new proposed model are in consistent with the oxygen activation of injectors. Interwell connectivity coefficient of each injector were calculated and the preponderance flow paths were found. Based on this, profile control were conducted. After profile control, the water injection efficiency of horizontal injectors obtained by this model improved and water cut of produces was reduced by 9% ~ 10%.\u0000 This technique has been used in nearly 100 wells of Bohai oilfields. With the inter-well connectivity method and the balanced injection string for horizontal wells, the development effect of reservoir with horizontal wells improved significantly.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75269520","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to share current operational challenges concerning Oil and Gas (O&G) operators, and to suggest certain solutions/applications from the IR4.0 technology toolbox. Augmented Reality/Virtual Reality (AR/VR) will be discussed to address the operational challenges detailed in this paper, while simultaneously showing how AR/VR can be leveraged to speed up knowledge transfer process, especially at the current alarming rates of attritions. The proposed approach is to first provide clear and concise explanation of the current challenges from an O&G operational point of view. Next, AR/VR will be explained and clearly defined to show its general benefits, before zooming in to innovate, and capitalize on specific features to address the challenges at hand. AR/VR can play a key role in managing other installed technologies (i.e. artificial intelligence, mobility, etc.) to transfer essential data to proper personnel at the right time and location. In other words, AR/VR can link up to all other applications and create one central hub to organize, streamline, and create actionable data in any facility. While showing the operational benefits, AR/VR will also be discussed to show how it can speed up knowledge transfer and reduce training costs, especially when software developers work together with O&G technologists to create meaningful product, rather than a generic one that truly serves no one. The result is showing that AR/VR can clearly solve and enhance O&G operations by delivering important prescriptive messages with knowledge-based actions to concerned parties at the proper location, so they can take timely, proactive actions. Simultaneously, acting ahead of time translates into reduced plant upsets, while increasing safety and well-being of all plant personnel. Most O&G companies employ stat-of-the-art technologies to address challenges affecting various parts of their operating facilities. Integrating these technologies and allowing operators to organize and strategize where and how to start, and showing potential links is itself a challenge. AR/VR can address this predicament, if employed properly. This paper will address AR/VR implicit and explicit capabilities in more details. The novelty of this paper is not in presenting AR/VR technology, as it has been around for several years, but rather in showing how to design an agile system to take advantage of the technology. The newly designed system can incorporate several scattered software applications across a facility; therefore AR/VR will act as an orchestrator by managing the flow of data and ensuring they reach the right personnel at the right time.
{"title":"Utilizing Immersive Technology to Enhance Plant Operations and Speed Up Knowledge Transfer","authors":"Hamad Balhareth","doi":"10.2523/iptc-22134-ea","DOIUrl":"https://doi.org/10.2523/iptc-22134-ea","url":null,"abstract":"\u0000 The objective of this paper is to share current operational challenges concerning Oil and Gas (O&G) operators, and to suggest certain solutions/applications from the IR4.0 technology toolbox. Augmented Reality/Virtual Reality (AR/VR) will be discussed to address the operational challenges detailed in this paper, while simultaneously showing how AR/VR can be leveraged to speed up knowledge transfer process, especially at the current alarming rates of attritions.\u0000 The proposed approach is to first provide clear and concise explanation of the current challenges from an O&G operational point of view. Next, AR/VR will be explained and clearly defined to show its general benefits, before zooming in to innovate, and capitalize on specific features to address the challenges at hand. AR/VR can play a key role in managing other installed technologies (i.e. artificial intelligence, mobility, etc.) to transfer essential data to proper personnel at the right time and location. In other words, AR/VR can link up to all other applications and create one central hub to organize, streamline, and create actionable data in any facility. While showing the operational benefits, AR/VR will also be discussed to show how it can speed up knowledge transfer and reduce training costs, especially when software developers work together with O&G technologists to create meaningful product, rather than a generic one that truly serves no one.\u0000 The result is showing that AR/VR can clearly solve and enhance O&G operations by delivering important prescriptive messages with knowledge-based actions to concerned parties at the proper location, so they can take timely, proactive actions. Simultaneously, acting ahead of time translates into reduced plant upsets, while increasing safety and well-being of all plant personnel.\u0000 Most O&G companies employ stat-of-the-art technologies to address challenges affecting various parts of their operating facilities. Integrating these technologies and allowing operators to organize and strategize where and how to start, and showing potential links is itself a challenge. AR/VR can address this predicament, if employed properly. This paper will address AR/VR implicit and explicit capabilities in more details.\u0000 The novelty of this paper is not in presenting AR/VR technology, as it has been around for several years, but rather in showing how to design an agile system to take advantage of the technology. The newly designed system can incorporate several scattered software applications across a facility; therefore AR/VR will act as an orchestrator by managing the flow of data and ensuring they reach the right personnel at the right time.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"128 20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78967095","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}
Carbonate reservoirs hold 60% of the world's oil and 40% of the gas. Therefore, developing high-impact and innovative technologies for well stimulation, such as foamed acid fracturing fluids, is essential for restoring well productivity and enhancing commercial productivity for carbonate reservoirs. Acid fracturing treatment is associated with reactivity control, fluid loss control, and conductivity generation challenges. For overcoming some drawbacks associated with conventional acid fracturing, foamed acid fluid is applied to enhance retardation, reduce water consumption, improve acid diversion, remove water or emulsion blocks, and improve conductivity generation. In this study, a unique foamed acid system stabilized by composite material was studied to develop fracturing fluid at 275-350 °F. In addition, the foam stability, rheology, and morphology characteristics were investigated using several characterization tools at 275-350 °F. The composite material comprises nanosheet (NS), and surfactant (SURF) were added to either a pure-acid or acid system that contains several additives for developing stable NS/SURF-based foamed acid fluid. To evaluate foam rheological properties and thermal stability at dynamic conditions, foam loop rheometer experiments were conducted at 275-350 °F, 1050 psi, and 70 % N2 quality. A high-resolution optical microscope was also utilized to observe foam texture morphology and further assess foam stability. In addition, foam-decaying time was observed by determining the foam-half-life-time (foam volume altering as a function of time). The static and dynamic results illustrated that foamed acid fluid stability and thermal adaptability were improved after adding composite material at 275-350 °F. The viscosity of foamed acid increased by double and its viscosity was higher than 45 cP at a shear rate of 300 S-1 and 350 °F. In addition, the foam-structure of NS/SURF-based foamed acid displayed a small hexagonal bubbles size, which positively affected the stability of foam to reach up to three hours at 300 °F. In contrast, the stability of pure foamed acid was one hour. This result is attributed to the adsorption of composite material at the liquid-gas interface layer that enhances the mechanical strength of the foam-layer (lamellae film) and provides a more robust barrier between the gas bubbles and liquid phase, resulting in delaying the coalescence of the bubbles. The developed NS/SURF-based foamed acid possesses several advantages over the conventional acid fracturing fluids: long stability, adequate viscosity (obtained without adding gelling agent), low water consumption, and high efficiency at 275-350 °F.
{"title":"A Novel Foamed Acid System Stabilized by Composite Material for Fracturing Applications","authors":"Abeer A. Alarawi, Bader Al Harbi, A. Busaleh","doi":"10.2523/iptc-22492-ms","DOIUrl":"https://doi.org/10.2523/iptc-22492-ms","url":null,"abstract":"\u0000 Carbonate reservoirs hold 60% of the world's oil and 40% of the gas. Therefore, developing high-impact and innovative technologies for well stimulation, such as foamed acid fracturing fluids, is essential for restoring well productivity and enhancing commercial productivity for carbonate reservoirs. Acid fracturing treatment is associated with reactivity control, fluid loss control, and conductivity generation challenges. For overcoming some drawbacks associated with conventional acid fracturing, foamed acid fluid is applied to enhance retardation, reduce water consumption, improve acid diversion, remove water or emulsion blocks, and improve conductivity generation. In this study, a unique foamed acid system stabilized by composite material was studied to develop fracturing fluid at 275-350 °F. In addition, the foam stability, rheology, and morphology characteristics were investigated using several characterization tools at 275-350 °F.\u0000 The composite material comprises nanosheet (NS), and surfactant (SURF) were added to either a pure-acid or acid system that contains several additives for developing stable NS/SURF-based foamed acid fluid. To evaluate foam rheological properties and thermal stability at dynamic conditions, foam loop rheometer experiments were conducted at 275-350 °F, 1050 psi, and 70 % N2 quality. A high-resolution optical microscope was also utilized to observe foam texture morphology and further assess foam stability. In addition, foam-decaying time was observed by determining the foam-half-life-time (foam volume altering as a function of time).\u0000 The static and dynamic results illustrated that foamed acid fluid stability and thermal adaptability were improved after adding composite material at 275-350 °F. The viscosity of foamed acid increased by double and its viscosity was higher than 45 cP at a shear rate of 300 S-1 and 350 °F. In addition, the foam-structure of NS/SURF-based foamed acid displayed a small hexagonal bubbles size, which positively affected the stability of foam to reach up to three hours at 300 °F. In contrast, the stability of pure foamed acid was one hour. This result is attributed to the adsorption of composite material at the liquid-gas interface layer that enhances the mechanical strength of the foam-layer (lamellae film) and provides a more robust barrier between the gas bubbles and liquid phase, resulting in delaying the coalescence of the bubbles. The developed NS/SURF-based foamed acid possesses several advantages over the conventional acid fracturing fluids: long stability, adequate viscosity (obtained without adding gelling agent), low water consumption, and high efficiency at 275-350 °F.","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":"75596431","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Sankaran, Diego Molinari, Hardikkumar Zalavadia, T. Stoddard, Wenyue Sun, Gagan Singh, Chris James
Economic pressure to improve production efficiency in unconventional reservoirs has met a stiff challenge to scale up traditional reservoir modeling methods to the entire field for quantifying well performance. The main reasons are lack of availability of key reservoir and well parameters and difficulty to setup and maintain models because of the large well count and rapid pace of operations. As a result, decline curve analysis is still the prevailing method for large scale evaluations, which does not consider routine pressure variations and operational constraints. Analytical rate transient (RTA) models warrant identification of flow regimes and geometrical assumptions (well and fractures) to apply discrete analytical models for various flow segments. This inherent limitation of RTA makes it interpretive and not conducive to fieldscale application, besides often lacking necessary inputs for all wells. It is desirable to have better understanding through a robust and consistent well performance analysis method at field scale to unlock significant production optimization opportunities with existing field infrastructure and investment. We have applied a reduced physics formulation based on Dynamic Drainage Volume (DDV) using commonly measured data for most wells (namely, flowback data, daily production rates, and wellhead pressure) to calculate continuous pressure depletion, transient productivity index (PI) and inflow performance relationship (IPR). This transient well performance (TWP) method eliminates the surface and wellbore operational impacts to extract the true reservoir signal that can be used for robust well performance analysis and forecasting. We applied the TWP method in multiple basins with large well counts (more than 1000 wells) producing under a variety of methods. In this paper, we present several case studies illustrating various production optimization opportunities, focusing on naturally flowing and gas-lifted wells. The fluid properties and bottomhole pressure estimated using data-driven methods for all wells provided excellent match with blind data (PVT lab reports and downhole gauge data). The TWP method normalizes reservoir and completion quality to extract valuable insights on effectiveness of well and completions design in the presence of varying geological and fluid properties. The transient PI and dynamic IPR results provided valuable insights on how and when to select various artificial lift systems. During gas lift, we identified several wells that were over-injecting gas volumes at higher compressor discharge head, with line of sight to significant operational cost savings and reduced energy consumption. The proposed methodology combines pragmatic use of physics and data-driven methods to solve a critical need for analyzing unconventional reservoirs. Field application of the novel DDV method on large well population has been quite successful in identifying various optimization opportunities that would not have b
{"title":"Unlocking Unconventional Production Optimization Opportunities Using Reduced Physics Models for Well Performance Analysis – Case Study","authors":"S. Sankaran, Diego Molinari, Hardikkumar Zalavadia, T. Stoddard, Wenyue Sun, Gagan Singh, Chris James","doi":"10.2523/iptc-22493-ms","DOIUrl":"https://doi.org/10.2523/iptc-22493-ms","url":null,"abstract":"\u0000 Economic pressure to improve production efficiency in unconventional reservoirs has met a stiff challenge to scale up traditional reservoir modeling methods to the entire field for quantifying well performance. The main reasons are lack of availability of key reservoir and well parameters and difficulty to setup and maintain models because of the large well count and rapid pace of operations. As a result, decline curve analysis is still the prevailing method for large scale evaluations, which does not consider routine pressure variations and operational constraints. Analytical rate transient (RTA) models warrant identification of flow regimes and geometrical assumptions (well and fractures) to apply discrete analytical models for various flow segments. This inherent limitation of RTA makes it interpretive and not conducive to fieldscale application, besides often lacking necessary inputs for all wells. It is desirable to have better understanding through a robust and consistent well performance analysis method at field scale to unlock significant production optimization opportunities with existing field infrastructure and investment.\u0000 We have applied a reduced physics formulation based on Dynamic Drainage Volume (DDV) using commonly measured data for most wells (namely, flowback data, daily production rates, and wellhead pressure) to calculate continuous pressure depletion, transient productivity index (PI) and inflow performance relationship (IPR). This transient well performance (TWP) method eliminates the surface and wellbore operational impacts to extract the true reservoir signal that can be used for robust well performance analysis and forecasting.\u0000 We applied the TWP method in multiple basins with large well counts (more than 1000 wells) producing under a variety of methods. In this paper, we present several case studies illustrating various production optimization opportunities, focusing on naturally flowing and gas-lifted wells. The fluid properties and bottomhole pressure estimated using data-driven methods for all wells provided excellent match with blind data (PVT lab reports and downhole gauge data). The TWP method normalizes reservoir and completion quality to extract valuable insights on effectiveness of well and completions design in the presence of varying geological and fluid properties. The transient PI and dynamic IPR results provided valuable insights on how and when to select various artificial lift systems. During gas lift, we identified several wells that were over-injecting gas volumes at higher compressor discharge head, with line of sight to significant operational cost savings and reduced energy consumption.\u0000 The proposed methodology combines pragmatic use of physics and data-driven methods to solve a critical need for analyzing unconventional reservoirs. Field application of the novel DDV method on large well population has been quite successful in identifying various optimization opportunities that would not have b","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"232 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80132601","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. Castañeda, Almohannad Alhashboul, A. Farzaneh, M. Sohrabi
The objective of this research is to analyze, for the first time to the author's best knowledge, how an oil and solution gas composition affects oil recovery and differential pressure when a whole core, saturated with live crude oil, is exposed to carbonated water injection. In the past, many authors independently conducted micro-model or small-diameter core floods to understand how carbonated water injection could affect the recovery of dead or live oil. However, only one author initiated a simple identification of the dominant role that hydrocarbon composition could play in the recovery factor of the system by using micro-models, which led to the development of this research. However, despite having partially identified the importance of this variable, and being a pioneer in this type of study, the author's analyses were limited to the mixture of methane with either C6, C10, C16, or C17, which is far from reality. Therefore, for the first time to our best knowledge, a new series of whole core flood experiments was performed, which involved the use of two types of crude oils, combined with three types of solution gases, two of which were multicomponent, to identify how compositional variability could affect oil recovery and differential pressure behavior when a whole core is exposed to carbonated water injection to displace these live crude oils. The obtained results led to the conclusion that the amount of formation of the new gas phase depends mainly on the molar percentage of the C1–C7 components in the live crude oil, which result in an increase in the oil recovery factor; more importantly, it will result in a higher differential pressure. It was also concluded that slight changes in the composition of the live crude oil do not have a significant effect on oil recovery but do have a significant effect on the behavior of the differential pressure. To our best knowledge, this significant impact has not yet been identified. Further analysis led to the conclusion that the impact on the differential pressure is not mainly due to the methane content but depends more on the content of C2–C7 components. Considering that the composition of the live crude oil is relevant for the formation of the new gas phase, and that the new gas phase can be considered as the dominant production mechanism for carbonated water injection in live crude oil, it was observed that the new gas phase has a significant effect on the oil effective permeability value, even reducing it by as much as half. In addition, the author proposed a new correlation to calculate the saturation of the new gas phase in scenarios of secondary injection of carbonated water in strongly water-wet environments. Finally, the system in which the highest recovery is achieved is the one with the richest gas, i.e., with the highest molar percentage of C1–C7 components, together with a non-water wet rock.
{"title":"An Experimental Investigation of the Effect of Oil/Gas Composition on the Performance of Carbonated Water Injection CWI","authors":"J. Castañeda, Almohannad Alhashboul, A. Farzaneh, M. Sohrabi","doi":"10.2523/iptc-22522-ms","DOIUrl":"https://doi.org/10.2523/iptc-22522-ms","url":null,"abstract":"\u0000 The objective of this research is to analyze, for the first time to the author's best knowledge, how an oil and solution gas composition affects oil recovery and differential pressure when a whole core, saturated with live crude oil, is exposed to carbonated water injection.\u0000 In the past, many authors independently conducted micro-model or small-diameter core floods to understand how carbonated water injection could affect the recovery of dead or live oil. However, only one author initiated a simple identification of the dominant role that hydrocarbon composition could play in the recovery factor of the system by using micro-models, which led to the development of this research. However, despite having partially identified the importance of this variable, and being a pioneer in this type of study, the author's analyses were limited to the mixture of methane with either C6, C10, C16, or C17, which is far from reality.\u0000 Therefore, for the first time to our best knowledge, a new series of whole core flood experiments was performed, which involved the use of two types of crude oils, combined with three types of solution gases, two of which were multicomponent, to identify how compositional variability could affect oil recovery and differential pressure behavior when a whole core is exposed to carbonated water injection to displace these live crude oils.\u0000 The obtained results led to the conclusion that the amount of formation of the new gas phase depends mainly on the molar percentage of the C1–C7 components in the live crude oil, which result in an increase in the oil recovery factor; more importantly, it will result in a higher differential pressure. It was also concluded that slight changes in the composition of the live crude oil do not have a significant effect on oil recovery but do have a significant effect on the behavior of the differential pressure. To our best knowledge, this significant impact has not yet been identified. Further analysis led to the conclusion that the impact on the differential pressure is not mainly due to the methane content but depends more on the content of C2–C7 components.\u0000 Considering that the composition of the live crude oil is relevant for the formation of the new gas phase, and that the new gas phase can be considered as the dominant production mechanism for carbonated water injection in live crude oil, it was observed that the new gas phase has a significant effect on the oil effective permeability value, even reducing it by as much as half.\u0000 In addition, the author proposed a new correlation to calculate the saturation of the new gas phase in scenarios of secondary injection of carbonated water in strongly water-wet environments.\u0000 Finally, the system in which the highest recovery is achieved is the one with the richest gas, i.e., with the highest molar percentage of C1–C7 components, together with a non-water wet rock.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73174107","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}
Carbon/Oxygen (C/O) log is the most commonly used measurement for reservoir saturation monitoring (RSM), especially in fresh water and mixed salinity environments. In interpreting C/O logs, oil carbon density (OCD) is a required input parameter, where a single averaging number from such as oil pressure-volume-temperature (PVT) tests is commonly used. An in-situ determined OCD, taking into account OCD variety areally as well as vertically across a reservoir, would improve the accuracy of CO RSM, the objective of this paper. In a previously published work, regions of different OCDs are identified based on available crude oil PVT data across the reservoir, and each of the regions is assigned a corresponding average OCD. Although this coarse regioning can provide improvements in determinations of oil saturation (So) from C/O logs, it can be further enhanced by taking into account variations of OCD across each region. In this paper, we discuss a new approach intended to increase the accuracy of the calculated So from C/O logging data, through the integration of a continuous oil density curve into the C/O data processing workflow. The new approach utilizes oil viscosity acquired from nuclear magnetic resonance (NMR) logs, in addition to temperature logs and PVT data, to develop a localized relationship between oil viscosity and oil density. The application of the optimum correlation shall yield an accurate oil density log, which is then used as a modular dynamic input of OCD in C/O data processing. The new workflow was applied to several wells across a heavy oil carbonate reservoir, with proven vertical change in oil properties. The comparison of the new with the original saturation profile, obtained by using the conventional C/O data interpretation workflow, showed a significant increase in accuracy. Where the new approach induced a better match to openhole – resistivity derived – water saturation log across heavy oil, with both good and moderate porosities, unperforated zones. Unlike the original data processing scheme which has usually over-estimated water saturation across the same zones, because of the lack of the required sensitivity towards the heavy hydrocarbon fraction. This new technique has been proven to closely capture the changes in reservoir oil properties, increasing the accuracy of water saturation profiling across reservoirs with varying oil properties, thus provides a means to maximize the benefit of C/O logging across reservoirs of varying hydrocarbon properties and optimize oilfield development.
{"title":"In-Situ Oil Carbon Density Characterization for Enhanced Reservoir Saturation Monitoring Using Carbon-Oxygen Logs","authors":"Y. Eltaher, S. Ma","doi":"10.2523/iptc-21976-ms","DOIUrl":"https://doi.org/10.2523/iptc-21976-ms","url":null,"abstract":"\u0000 Carbon/Oxygen (C/O) log is the most commonly used measurement for reservoir saturation monitoring (RSM), especially in fresh water and mixed salinity environments. In interpreting C/O logs, oil carbon density (OCD) is a required input parameter, where a single averaging number from such as oil pressure-volume-temperature (PVT) tests is commonly used. An in-situ determined OCD, taking into account OCD variety areally as well as vertically across a reservoir, would improve the accuracy of CO RSM, the objective of this paper.\u0000 In a previously published work, regions of different OCDs are identified based on available crude oil PVT data across the reservoir, and each of the regions is assigned a corresponding average OCD. Although this coarse regioning can provide improvements in determinations of oil saturation (So) from C/O logs, it can be further enhanced by taking into account variations of OCD across each region. In this paper, we discuss a new approach intended to increase the accuracy of the calculated So from C/O logging data, through the integration of a continuous oil density curve into the C/O data processing workflow. The new approach utilizes oil viscosity acquired from nuclear magnetic resonance (NMR) logs, in addition to temperature logs and PVT data, to develop a localized relationship between oil viscosity and oil density. The application of the optimum correlation shall yield an accurate oil density log, which is then used as a modular dynamic input of OCD in C/O data processing.\u0000 The new workflow was applied to several wells across a heavy oil carbonate reservoir, with proven vertical change in oil properties. The comparison of the new with the original saturation profile, obtained by using the conventional C/O data interpretation workflow, showed a significant increase in accuracy. Where the new approach induced a better match to openhole – resistivity derived – water saturation log across heavy oil, with both good and moderate porosities, unperforated zones. Unlike the original data processing scheme which has usually over-estimated water saturation across the same zones, because of the lack of the required sensitivity towards the heavy hydrocarbon fraction. This new technique has been proven to closely capture the changes in reservoir oil properties, increasing the accuracy of water saturation profiling across reservoirs with varying oil properties, thus provides a means to maximize the benefit of C/O logging across reservoirs of varying hydrocarbon properties and optimize oilfield development.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"1038 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77637759","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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