Cyclic steam simulation (CSS) was widely used to recover heavy oil in shallow reservoirs in Kazakhstan. In the late stage of CSS in M oilfield, the performance of this CSS project was poor with high water cut and low oil steam ratio (OSR), indicating low economic benefit. The multi-component thermal fluid (MTF) stimulation trial has been conducted there since March 2018 to evaluate the feasibility of this technology. This paper introduces the field experience and the production performance of MTF stimulation. Results are from 32 cycles of MTF stimulations in 23 wells, most of which had completed their 4 cycles of CSS before. MTF technology is based on a high-pressure jet combustion mechanism, generating a mixture of nitrogen, carbon dioxide and vapor (MTF) under a sealed combustion condition. The mixture fluid provides a significant enhancement through a synergistic effect in the reservoir. The soaking and recovery process are the same as the conventional steam stimulation, meanwhile the requirements for completion and wellbore structure are the same as well. By the time of statistic, average cyclic OSR reaches 2.19 from 0.49 of last CSS cycle. Average water cut declines from 90% to 40% and daily oil production rises from 22 bbls to 33 bbls. Free water is almost invisible in the produced fluid, instead, a stable quasi-monophasic flow has been presented even at low temperatures. This effectively increases the fluidity and dilatancy of crude oil, and greatly replenishes the elastic energy of the formation. Meanwhile, with all components injected into the formation, MTF stimulation achieves significant reduction in carbon emissions. Although this is a pilot test, considerable economic benefits have been achieved with the increase of oil production efficiency. MTF stimulation brings an additional profit of USD 4.4 million for the first year under conditions of local material's cost. This successful pilot demonstrates that MTF stimulation may play an important role at late stage of CSS, even it has its own prospect in an initial heavy oil reservoir development. In the meantime, this pilot experience can be used as a reference for other similar reservoirs’ development.
{"title":"Pilot Project: Application of Multi-Component Thermal Fluid Stimulation on Shallow Heavy Oil Reservoir in Kazakhstan","authors":"Leihao Yi, X. Hua, Wenlong Guan, Shiguo Xu, Ziyi Zhang, Yizhong Mei, E. Guo, Junping Liu, Li Zhong, Guohui Liu, Xiaoman Zheng, Zhang Wei","doi":"10.2118/204818-ms","DOIUrl":"https://doi.org/10.2118/204818-ms","url":null,"abstract":"Cyclic steam simulation (CSS) was widely used to recover heavy oil in shallow reservoirs in Kazakhstan. In the late stage of CSS in M oilfield, the performance of this CSS project was poor with high water cut and low oil steam ratio (OSR), indicating low economic benefit. The multi-component thermal fluid (MTF) stimulation trial has been conducted there since March 2018 to evaluate the feasibility of this technology.\u0000 This paper introduces the field experience and the production performance of MTF stimulation. Results are from 32 cycles of MTF stimulations in 23 wells, most of which had completed their 4 cycles of CSS before.\u0000 MTF technology is based on a high-pressure jet combustion mechanism, generating a mixture of nitrogen, carbon dioxide and vapor (MTF) under a sealed combustion condition. The mixture fluid provides a significant enhancement through a synergistic effect in the reservoir. The soaking and recovery process are the same as the conventional steam stimulation, meanwhile the requirements for completion and wellbore structure are the same as well. By the time of statistic, average cyclic OSR reaches 2.19 from 0.49 of last CSS cycle. Average water cut declines from 90% to 40% and daily oil production rises from 22 bbls to 33 bbls. Free water is almost invisible in the produced fluid, instead, a stable quasi-monophasic flow has been presented even at low temperatures. This effectively increases the fluidity and dilatancy of crude oil, and greatly replenishes the elastic energy of the formation. Meanwhile, with all components injected into the formation, MTF stimulation achieves significant reduction in carbon emissions.\u0000 Although this is a pilot test, considerable economic benefits have been achieved with the increase of oil production efficiency. MTF stimulation brings an additional profit of USD 4.4 million for the first year under conditions of local material's cost. This successful pilot demonstrates that MTF stimulation may play an important role at late stage of CSS, even it has its own prospect in an initial heavy oil reservoir development. In the meantime, this pilot experience can be used as a reference for other similar reservoirs’ development.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76565300","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}
Xiujuan He, W. Lei, Xin Xu, Jian Xu, J. Qiu, Wei Dai, Leyu Cui, Jun Ma, Z. Shen, Yingcheng Li
Two foaming formulations, an amphoteric surfactant (noted as Fam) and a blend of anionic-cationic-amphoteric surfactants (noted as Facam) have been prepared and tested at lab and in field in the presence of high content of condensate (60 vol% on average). Foam height with Facam are close to those with Fam. Although Fam has better foam stability without condensate, the half-life of the foam (t1/2) decreases by 50% in presence of condensate. Foam generated by Facam shows better oil resistance performance due to negative spreading coefficient (S). Liquid unloading efficiency with Facam are close to those with Fam at lab. Nevertheless in field application, Facam is more efficient than Fam for the deliquification in the gas well. The depth of gas well is 2126 m. Foaming formulations were injected respectively from casing pipe with injection amount of 1-2kg/day. The pressure difference between casing and tubing pipes (ΔPc-t) decreased from 1.0 MPa to 0.28 MPa, and the decline of gas production was slowed down after the injection of Facam in the gas well. As a contrast, both theΔPc-t and decline rate of gas production were increased with Fam. Foam resistance to condensate is a factor, while emulsion viscosity is inferred to be another crucial factor for the performance of formulations in the deliquification process.
{"title":"Gas Well Deliquification in the Presence of High Content of Condensate: From Laboratory to Field Test","authors":"Xiujuan He, W. Lei, Xin Xu, Jian Xu, J. Qiu, Wei Dai, Leyu Cui, Jun Ma, Z. Shen, Yingcheng Li","doi":"10.2118/204657-ms","DOIUrl":"https://doi.org/10.2118/204657-ms","url":null,"abstract":"\u0000 Two foaming formulations, an amphoteric surfactant (noted as Fam) and a blend of anionic-cationic-amphoteric surfactants (noted as Facam) have been prepared and tested at lab and in field in the presence of high content of condensate (60 vol% on average). Foam height with Facam are close to those with Fam. Although Fam has better foam stability without condensate, the half-life of the foam (t1/2) decreases by 50% in presence of condensate. Foam generated by Facam shows better oil resistance performance due to negative spreading coefficient (S). Liquid unloading efficiency with Facam are close to those with Fam at lab. Nevertheless in field application, Facam is more efficient than Fam for the deliquification in the gas well. The depth of gas well is 2126 m. Foaming formulations were injected respectively from casing pipe with injection amount of 1-2kg/day. The pressure difference between casing and tubing pipes (ΔPc-t) decreased from 1.0 MPa to 0.28 MPa, and the decline of gas production was slowed down after the injection of Facam in the gas well. As a contrast, both theΔPc-t and decline rate of gas production were increased with Fam. Foam resistance to condensate is a factor, while emulsion viscosity is inferred to be another crucial factor for the performance of formulations in the deliquification process.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74865490","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}
Shijun Huang, Yuanrui Zhu, Shichao Chai, G. Ding, Yicheng Xin, Peiyu Li
A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.
{"title":"A Practical Model for Water Injection Evaluation and Optimization in Typical Offshore Reservoirs Considering Formation Heterogeneity Based on Experimental Study","authors":"Shijun Huang, Yuanrui Zhu, Shichao Chai, G. Ding, Yicheng Xin, Peiyu Li","doi":"10.2118/204605-ms","DOIUrl":"https://doi.org/10.2118/204605-ms","url":null,"abstract":"\u0000 A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a \"U\" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed \"U\" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed \"U\" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88806525","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}
Cavings are a valuable source of information when drilling operations are being performed, and multiple parameters can contribute to producing cavings which indicate that failure has occurred or is about to occur downhole. This study will describe a project which is an integrated study of Machine Learning, Computer Vision, Geology, and Photography so that the recognition of cavings in the shaker is possible and how to link the cavings morphology with causal mechanisms related to wellbore instability problems. This study aims to develop a model which can extract caving features such as Shape, Edge Definition, Color, and Size. One of the core aspects of this study was to develop a structured image database of cavings from the Norwegian Continental Shelf which contains important feature information and the application of different algorithms used for automation enabled several opportunities to analyze and identify causal mechanism related to wellbore instability problems in real-time. As a result of that, the drilling operations would experience an improvement in terms of a faster decision-making process to solve operative problems related to wellbore stability which will lead to optimization not only in time and resources but also in safer drilling operations. Different algorithms and artificial intelligence tools were used to investigate the best approach to correctly detect and derive meaningful information about the shape, color size and edge from cavings like supervised learning, unsupervised learning, neural networks and computer vision. A key part of this study was image augmentation which plays a significant role for the detection of the cavings and their features. Multiple data sets can be created, and by using data augmentation, this will enable recognition of more complex patterns that will have on-rig applicability. Also, this new approach can deliver multiple outcomes besides failure mechanism identification such as volume of rocks being drilled, transport of cutting, type of formation being drilled.
{"title":"Integration of Neural Networks and Wellbore Stability, a Modern Approach to Recognize Drilling Problems Through Computer Vision","authors":"Carlos Andres Izurieta, L. Vargas","doi":"10.2118/204760-ms","DOIUrl":"https://doi.org/10.2118/204760-ms","url":null,"abstract":"\u0000 Cavings are a valuable source of information when drilling operations are being performed, and multiple parameters can contribute to producing cavings which indicate that failure has occurred or is about to occur downhole. This study will describe a project which is an integrated study of Machine Learning, Computer Vision, Geology, and Photography so that the recognition of cavings in the shaker is possible and how to link the cavings morphology with causal mechanisms related to wellbore instability problems. This study aims to develop a model which can extract caving features such as Shape, Edge Definition, Color, and Size.\u0000 One of the core aspects of this study was to develop a structured image database of cavings from the Norwegian Continental Shelf which contains important feature information and the application of different algorithms used for automation enabled several opportunities to analyze and identify causal mechanism related to wellbore instability problems in real-time. As a result of that, the drilling operations would experience an improvement in terms of a faster decision-making process to solve operative problems related to wellbore stability which will lead to optimization not only in time and resources but also in safer drilling operations.\u0000 Different algorithms and artificial intelligence tools were used to investigate the best approach to correctly detect and derive meaningful information about the shape, color size and edge from cavings like supervised learning, unsupervised learning, neural networks and computer vision. A key part of this study was image augmentation which plays a significant role for the detection of the cavings and their features. Multiple data sets can be created, and by using data augmentation, this will enable recognition of more complex patterns that will have on-rig applicability. Also, this new approach can deliver multiple outcomes besides failure mechanism identification such as volume of rocks being drilled, transport of cutting, type of formation being drilled.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-06-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84869083","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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