This paper demonstrates how electromagnetic induction heating is used for bitumen recovery from the Athabasca oil sands in Alberta with minimal external water requirements. The paper addresses the setup requirements and the necessary parameters for this method to achieve an economic energy to oil ratio. An iterative process is followed to couple the heat rate generated by electromagnetic induction heating to the reservoir model over a defined period. The reservoir model represents a 33 meter payzone with properties for the lower McMurray formation in an area north of Fort McMurray within the Athabasca oil sands deposit. Several scenarios are extensively explored to reach the most practical and feasible setup for oil recovery. The process enables operators to monitor and control reservoir pressure and temperature, liquid production, and energy to oil ratio to maximize recovery from oil sands and heavy oil reservoirs. The results show an expected ultimate oil recovery factor of +70% with an average energy to oil ratio that is lower than the average ratio associated with steam assisted gravity drainage. It is observed that the amount of energy required by the process correlates with water saturation in the near wellbore region, higher water saturation levels are preferred for enhanced oil recovery. It is also noticed that majority of the electromagnetically induced heat rate is generated in the near wellbore region vaporizing any existing water in that region, which eventually slows down the heating process. However, water injection improves the heat convection further into the reservoir, and therefore is essential for establishing a steam chamber using this method. Nevertheless, the volume of injected water required to establish a steam chamber is comparable to the overall volume of water produced from the reservoir, and thus minimal external water is necessary in this process. Moreover, the method is emissions free because heat is generated in the reservoir using an electrically powered downhole inductor (patent pending) that transfers electromagnetic energy to heat. In conclusion, this novel method shows high potential for responsible oil recovery from oil sands and heavy oil reservoirs while meeting economic and environmental expectations. This paper presents the use of a novel clean energy technology to recover bitumen from the Athabasca oil sands in Alberta. Furthermore, the technology is of high value to oil production from heavy oil reservoirs around the world and therefore provides large benefits to the energy industry.
{"title":"Electromagnetic Induction Heating for Bitumen Recovery: A Case Study in Athabasca Oil Sands","authors":"A. Sherwali, M. Noroozi, W. Dunford","doi":"10.2118/206403-ms","DOIUrl":"https://doi.org/10.2118/206403-ms","url":null,"abstract":"\u0000 This paper demonstrates how electromagnetic induction heating is used for bitumen recovery from the Athabasca oil sands in Alberta with minimal external water requirements. The paper addresses the setup requirements and the necessary parameters for this method to achieve an economic energy to oil ratio.\u0000 An iterative process is followed to couple the heat rate generated by electromagnetic induction heating to the reservoir model over a defined period. The reservoir model represents a 33 meter payzone with properties for the lower McMurray formation in an area north of Fort McMurray within the Athabasca oil sands deposit. Several scenarios are extensively explored to reach the most practical and feasible setup for oil recovery. The process enables operators to monitor and control reservoir pressure and temperature, liquid production, and energy to oil ratio to maximize recovery from oil sands and heavy oil reservoirs.\u0000 The results show an expected ultimate oil recovery factor of +70% with an average energy to oil ratio that is lower than the average ratio associated with steam assisted gravity drainage. It is observed that the amount of energy required by the process correlates with water saturation in the near wellbore region, higher water saturation levels are preferred for enhanced oil recovery. It is also noticed that majority of the electromagnetically induced heat rate is generated in the near wellbore region vaporizing any existing water in that region, which eventually slows down the heating process. However, water injection improves the heat convection further into the reservoir, and therefore is essential for establishing a steam chamber using this method. Nevertheless, the volume of injected water required to establish a steam chamber is comparable to the overall volume of water produced from the reservoir, and thus minimal external water is necessary in this process. Moreover, the method is emissions free because heat is generated in the reservoir using an electrically powered downhole inductor (patent pending) that transfers electromagnetic energy to heat. In conclusion, this novel method shows high potential for responsible oil recovery from oil sands and heavy oil reservoirs while meeting economic and environmental expectations. This paper presents the use of a novel clean energy technology to recover bitumen from the Athabasca oil sands in Alberta. Furthermore, the technology is of high value to oil production from heavy oil reservoirs around the world and therefore provides large benefits to the energy industry.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83490390","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}
Stanislav Vladimirovich Tuzhilkin, Filipp Igorevich Brednev, Andrey Vladimirovich Yastreb, R. Uchuev, A. E. Parshakov, Rustam Ravilievich Zubaidullin, A. Islamov, A. A. Burkov
The article presents geological substantiations, the process and the results of the construction of a multilateral well with multistage fracturing from the existing producing well in the Yuzhno-Priobskoye field. The scope of construction of a multilateral TAML-3 well as per the international classification with a saved mainbore was to prove the effectiveness of the multilateral technology and its economic feasibility in the conditions of an extensive stock of producing wells. Every year we are seeing an increasing number of new wells being drilled in reservoirs with worsening characteristics which is caused by low permeability. Sharp production declines (up to 70% in the first year) and an increasing amount of periodic wells highlight the need to advance well stimulation methods. Well workovers by drilling a horizontal lateral while keeping the mainbore in operation allows to increase the production rate by 30% compared to a conventional sidetracking. While keeping the production rate of the mainbore, this technology provides for an additional production from a lateral bore and allows to operate the well at the planned bottomhole pressure.
{"title":"TAML-3 Multilateral Wells Construction with Multi-Stage Fracturing in Producing Wells","authors":"Stanislav Vladimirovich Tuzhilkin, Filipp Igorevich Brednev, Andrey Vladimirovich Yastreb, R. Uchuev, A. E. Parshakov, Rustam Ravilievich Zubaidullin, A. Islamov, A. A. Burkov","doi":"10.2118/206451-ms","DOIUrl":"https://doi.org/10.2118/206451-ms","url":null,"abstract":"\u0000 The article presents geological substantiations, the process and the results of the construction of a multilateral well with multistage fracturing from the existing producing well in the Yuzhno-Priobskoye field. The scope of construction of a multilateral TAML-3 well as per the international classification with a saved mainbore was to prove the effectiveness of the multilateral technology and its economic feasibility in the conditions of an extensive stock of producing wells.\u0000 Every year we are seeing an increasing number of new wells being drilled in reservoirs with worsening characteristics which is caused by low permeability. Sharp production declines (up to 70% in the first year) and an increasing amount of periodic wells highlight the need to advance well stimulation methods. Well workovers by drilling a horizontal lateral while keeping the mainbore in operation allows to increase the production rate by 30% compared to a conventional sidetracking. While keeping the production rate of the mainbore, this technology provides for an additional production from a lateral bore and allows to operate the well at the planned bottomhole pressure.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90948242","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}
Maxim Viktorovich Miklyaev, Ivan Denisov, Ivan Mikhailovich Gavrilin
Well construction in the Volga-Ural Region faces different sorts of complications, the most common ones being the loss of drilling fluids and rockslides. Such complications may cause considerable financial losses due to non-productive time (NPT) and longer well construction periods. Moreover, there are complications, which might occur both during well construction and during its exploitation. The commonest complications are sustained casing pressure (SCP) and annular flow. The complications, which occur when operating a well, also have a negative effect on the economic efficiency of well operation and call for additional actions, for example, repair and insulation works, which require well shutdown and killing, though a desired outcome still cannot be guaranteed; moreover, it is possible that several different operations may have to be carried out. In addition, the occurrence of SCP during well life is one of the most crucial problems that may cause well abandonment due to high risks posed by its operation. It is known that the main reasons for SCP are as follows: Channels in cement stone Casing leaks Leaks in wellhead connections To resolve the problem of cement stone channeling, several measures were taken, such as revising cement slurry designs, cutting time for setting strings on slips, applying two-stage cementing, etc. These measures were not successful, besides, they caused additional expenses for extra equipment (for example, a cementer). In order to reduce the risk of cement stone channeling, a cementing method is required that will allow to apply excess pressure on cement slurry during the period of transition and early strength development. To achieve this goal, a well-known method of controlled pressure cementing may be applied. Its main drawback, however, is that it requires much extra equipment, thus increasing operation expenses. In addition, the abovementioned method allows affecting the cement stone only during the operation process and / or during the waiting on cement (WOC) time. Upon receiving the results of the implemented measures and considering the existing technologies and evaluating the economic efficiency, the need was flagged for developing a combined cementing method. The goal of this method is to modify the production string cementing method with a view to applying excess pressure on cement stone during strength development and throughout the well lifecycle. The introduction of this lining method does not lead to an increase in well construction costs and considerably reduces the risks of losing a well from the production well stock.
{"title":"Development and Implementation of the Method of Cementing Production Casing 178 mm with Pressure on the Cement Slurry on the East Part of the Orenburg Oil and Gas Condensate Field","authors":"Maxim Viktorovich Miklyaev, Ivan Denisov, Ivan Mikhailovich Gavrilin","doi":"10.2118/206454-ms","DOIUrl":"https://doi.org/10.2118/206454-ms","url":null,"abstract":"\u0000 Well construction in the Volga-Ural Region faces different sorts of complications, the most common ones being the loss of drilling fluids and rockslides. Such complications may cause considerable financial losses due to non-productive time (NPT) and longer well construction periods. Moreover, there are complications, which might occur both during well construction and during its exploitation. The commonest complications are sustained casing pressure (SCP) and annular flow.\u0000 The complications, which occur when operating a well, also have a negative effect on the economic efficiency of well operation and call for additional actions, for example, repair and insulation works, which require well shutdown and killing, though a desired outcome still cannot be guaranteed; moreover, it is possible that several different operations may have to be carried out.\u0000 In addition, the occurrence of SCP during well life is one of the most crucial problems that may cause well abandonment due to high risks posed by its operation. It is known that the main reasons for SCP are as follows:\u0000 Channels in cement stone Casing leaks Leaks in wellhead connections\u0000 To resolve the problem of cement stone channeling, several measures were taken, such as revising cement slurry designs, cutting time for setting strings on slips, applying two-stage cementing, etc. These measures were not successful, besides, they caused additional expenses for extra equipment (for example, a cementer). In order to reduce the risk of cement stone channeling, a cementing method is required that will allow to apply excess pressure on cement slurry during the period of transition and early strength development. To achieve this goal, a well-known method of controlled pressure cementing may be applied. Its main drawback, however, is that it requires much extra equipment, thus increasing operation expenses. In addition, the abovementioned method allows affecting the cement stone only during the operation process and / or during the waiting on cement (WOC) time.\u0000 Upon receiving the results of the implemented measures and considering the existing technologies and evaluating the economic efficiency, the need was flagged for developing a combined cementing method. The goal of this method is to modify the production string cementing method with a view to applying excess pressure on cement stone during strength development and throughout the well lifecycle. The introduction of this lining method does not lead to an increase in well construction costs and considerably reduces the risks of losing a well from the production well stock.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89849186","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Norkina, Sergey Mihailovich Karpukhin, K. Ruban, Y. Petrakov, A. Sobolev
The design features and the need to use a water-based solution make the task of ensuring trouble-free drilling of vertical wells non-trivial. This work is an example of an interdisciplinary approach to the analysis of the mechanisms of instability of the wellbore. Instability can be caused by a complex of reasons, in this case, standard geomechanical calculations are not enough to solve the problem. Engineering calculations and laboratory chemical studies are integrated into the process of geomechanical modeling. The recommendations developed in all three areas are interdependent and inseparable from each other. To achieve good results, it is necessary to comply with a set of measures at the same time. The key tasks of the project were: determination of drilling density, tripping the pipe conditions, parameters of the drilling fluid rheology, selection of a system for the best inhibition of clay swelling.
{"title":"Interdisciplinary Approach for Wellbore Stability During Slimhole Drilling at Volga-Urals Basin Oilfield","authors":"A. Norkina, Sergey Mihailovich Karpukhin, K. Ruban, Y. Petrakov, A. Sobolev","doi":"10.2118/206562-ms","DOIUrl":"https://doi.org/10.2118/206562-ms","url":null,"abstract":"\u0000 The design features and the need to use a water-based solution make the task of ensuring trouble-free drilling of vertical wells non-trivial.\u0000 This work is an example of an interdisciplinary approach to the analysis of the mechanisms of instability of the wellbore. Instability can be caused by a complex of reasons, in this case, standard geomechanical calculations are not enough to solve the problem.\u0000 Engineering calculations and laboratory chemical studies are integrated into the process of geomechanical modeling.\u0000 The recommendations developed in all three areas are interdependent and inseparable from each other. To achieve good results, it is necessary to comply with a set of measures at the same time.\u0000 The key tasks of the project were: determination of drilling density, tripping the pipe conditions, parameters of the drilling fluid rheology, selection of a system for the best inhibition of clay swelling.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73072835","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. Vershinin, A. Blyablyas, D. A. Golovanov, A. Penigin, N. Glavnov
The problem of associated petroleum gas utilization is especially urgent for fields located far from infrastructure facilities for raw gas transportation and treatment. For such fields, alternative methods of gas utilization, especially gas re-injection, are becoming relevant. The re-injection options include: injection into underground reservoir for storage (if there are reservoirs suitable for injection near the field), injection into a gas cap, if any, or injection into a productive reservoir. The latter method allows, along with solving the problem of gas disposal, to increase oil recovery. This study describes an example of miscible gas injection into the reservoir at the Chatylkinskoye field, the infrastructure assumptions which make this option a better one versus a selling option, and the features of a gas treatment and injection process.
{"title":"Technological Features of Associated Petroleum Gas Miscible Injection MGI in Order to Increase Oil Recovery at a Remote Group of Fields in Western Siberia","authors":"S. Vershinin, A. Blyablyas, D. A. Golovanov, A. Penigin, N. Glavnov","doi":"10.2118/206497-ms","DOIUrl":"https://doi.org/10.2118/206497-ms","url":null,"abstract":"\u0000 The problem of associated petroleum gas utilization is especially urgent for fields located far from infrastructure facilities for raw gas transportation and treatment. For such fields, alternative methods of gas utilization, especially gas re-injection, are becoming relevant. The re-injection options include: injection into underground reservoir for storage (if there are reservoirs suitable for injection near the field), injection into a gas cap, if any, or injection into a productive reservoir. The latter method allows, along with solving the problem of gas disposal, to increase oil recovery. This study describes an example of miscible gas injection into the reservoir at the Chatylkinskoye field, the infrastructure assumptions which make this option a better one versus a selling option, and the features of a gas treatment and injection process.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72690756","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}
N. Abaltusov, Anton Sergeevich Ryabov, Artem Evgenevich Perunov, S. S. Rublev, S. A. Mitrokhin, Igor Yurevich Mukhachev, Roman Gennadevich Fomchenko
The pressing challenge is the abnormally rapid wear of well logging equipment and drilling tools when drilling wells in pay zone of Chayandinskoye field. Wear-out of BHA stabilizers within one run makes directional drilling inefficient and results in additional trips to replace equipment. Wear-out of drill pipes results in emergencies risk increase. To prevent such incidents the necessity arises to conduct an unscheduled inspection, reject and replace drilling tools. All these conditions entail increase in drilling time and decline in profitability. Problem analysis and expert review was made by drilling optimization specialists from DD Contractor jointly with the experts from R&D Center and Operator Company. This paper discusses how cooperation of the engineers from three companies as well as a particular approach to incident investigation and drilling engineering made it possible to identify the most critical factors, which contribute to a standard BHA wear, to work out measures to prevent similar situations in future and select an alternative BHA. The gained experience has been successfully disseminated to the other wells in Chayandinskoye field and other fields in Eastern Siberia; and the incident investigation methods and drilling engineering procedures are effectively applied under the other projects.
{"title":"Application of the Advanced Methods to Investigate Incidents and Drilling Engineering Principles to Prevent Critical Wear-Out of Downhole Equipment When Drilling Wells in Chayandinskoye Field","authors":"N. Abaltusov, Anton Sergeevich Ryabov, Artem Evgenevich Perunov, S. S. Rublev, S. A. Mitrokhin, Igor Yurevich Mukhachev, Roman Gennadevich Fomchenko","doi":"10.2118/206452-ms","DOIUrl":"https://doi.org/10.2118/206452-ms","url":null,"abstract":"\u0000 The pressing challenge is the abnormally rapid wear of well logging equipment and drilling tools when drilling wells in pay zone of Chayandinskoye field. Wear-out of BHA stabilizers within one run makes directional drilling inefficient and results in additional trips to replace equipment. Wear-out of drill pipes results in emergencies risk increase. To prevent such incidents the necessity arises to conduct an unscheduled inspection, reject and replace drilling tools. All these conditions entail increase in drilling time and decline in profitability.\u0000 Problem analysis and expert review was made by drilling optimization specialists from DD Contractor jointly with the experts from R&D Center and Operator Company.\u0000 This paper discusses how cooperation of the engineers from three companies as well as a particular approach to incident investigation and drilling engineering made it possible to identify the most critical factors, which contribute to a standard BHA wear, to work out measures to prevent similar situations in future and select an alternative BHA.\u0000 The gained experience has been successfully disseminated to the other wells in Chayandinskoye field and other fields in Eastern Siberia; and the incident investigation methods and drilling engineering procedures are effectively applied under the other projects.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89004741","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. S. Nikolaev, N. Moeininia, H. Ott, Hagen Bueltemeier
Underground bio-methanation is a promising technology for large-scale renewable energy storage. Additionally, it enables the recycling of CO2 via the generation of "renewable methane" in porous reservoirs using in-situ microbes as bio-catalysts. Potential candidate reservoirs are depleted gas fields or even abandoned gas storages, providing enormous storage capacity to balance seasonal energy supply and demand fluctuations. This paper discusses the underlying bio-methanation process as part of the ongoing research project "Bio-UGS – Biological conversion of carbon dioxide and hydrogen to methane," funded by the German Federal Ministry of Education and Research (BMBF). First, the hydrodynamic processes are assessed, and a review of the related microbial processes is provided. Then, based on exemplary field-scale simulations, the bio-reactive transport process and its consequences for operation are evaluated. The hydrogen conversion process was investigated by numerical simulations on field scale. For this, a two-phase multi-component bio-reactive transport model was implemented by (Hagemann 2018) in the open-source DuMux (Flemisch et al. 2011) simulation toolkit for porous media flow. The underlying processes include the transport of reactants and products, consumption of specific components, and the related growth and decay of the microbial population, resulting in a bio-reactive transport model. The microbial kinetic parameters of methanogenic reactions are taken from the available literature. The simulation study covers different scenarios on conceptional field-scale models, studying the impact of well placement, injection rates, and gas compositions. Due to a significant sensitivity of the simulation results to the bio-conversion kinetics, the field-specific conversion rates must be obtained. Thus, the Bio-UGS project is accompanied by laboratory experiments out of the frame of this paper. Other parameters are rather a matter of design; in the present case of depleted gas fields, those parameters are coupled and can be chosen to convert fully hydrogen and carbon dioxide to methane. Especially the well spacing can be considered the main design parameter in the likely case of a given injection rate and gas composition. This study extends the application of the previously developed code from a homogeneous-2D to the heterogeneous-3D case. The simulations mimic the co-injection of carbon dioxide and hydrogen from a 40 MW electrolysis.
地下生物甲烷化是一种很有前途的大规模可再生能源存储技术。此外，它还可以利用原位微生物作为生物催化剂，通过在多孔储层中产生“可再生甲烷”来回收二氧化碳。潜在的候选储层是枯竭的气田，甚至是废弃的储气库，提供巨大的存储容量，以平衡季节性能源供需波动。本文讨论了潜在的生物甲烷化过程，作为由德国联邦教育和研究部(BMBF)资助的正在进行的研究项目“Bio-UGS -二氧化碳和氢气向甲烷的生物转化”的一部分。首先，对水动力过程进行了评估，并对相关的微生物过程进行了综述。然后，基于典型的现场规模模拟，评估了生物反应性输运过程及其对操作的影响。通过现场数值模拟研究了氢气转化过程。为此，(Hagemann 2018)在开源的DuMux (Flemisch et al. 2011)多孔介质流模拟工具包中实现了两相多组分生物反应输运模型。潜在的过程包括反应物和产物的运输，特定成分的消耗，以及微生物种群的相关生长和衰变，从而形成生物反应性运输模型。产甲烷反应的微生物动力学参数取自现有文献。模拟研究涵盖了概念油田规模模型的不同场景，研究了井位、注入速率和气体成分的影响。由于模拟结果对生物转化动力学非常敏感，因此必须获得特定领域的转化率。因此，Bio-UGS项目伴随着本文框架之外的实验室实验。其他参数则是设计问题;在目前枯竭气田的情况下，这些参数是耦合的，可以选择将氢和二氧化碳完全转化为甲烷。特别是在给定注入速度和气体成分的可能情况下，井距可以被认为是主要设计参数。本研究将先前开发的代码的应用从均匀2d扩展到非均匀3d情况。模拟模拟了40兆瓦电解过程中二氧化碳和氢气的共注入。
{"title":"Investigation of Underground Bio-Methanation Using Bio-Reactive Transport Modeling","authors":"D. S. Nikolaev, N. Moeininia, H. Ott, Hagen Bueltemeier","doi":"10.2118/206617-ms","DOIUrl":"https://doi.org/10.2118/206617-ms","url":null,"abstract":"\u0000 Underground bio-methanation is a promising technology for large-scale renewable energy storage. Additionally, it enables the recycling of CO2 via the generation of \"renewable methane\" in porous reservoirs using in-situ microbes as bio-catalysts. Potential candidate reservoirs are depleted gas fields or even abandoned gas storages, providing enormous storage capacity to balance seasonal energy supply and demand fluctuations. This paper discusses the underlying bio-methanation process as part of the ongoing research project \"Bio-UGS – Biological conversion of carbon dioxide and hydrogen to methane,\" funded by the German Federal Ministry of Education and Research (BMBF). First, the hydrodynamic processes are assessed, and a review of the related microbial processes is provided. Then, based on exemplary field-scale simulations, the bio-reactive transport process and its consequences for operation are evaluated.\u0000 The hydrogen conversion process was investigated by numerical simulations on field scale. For this, a two-phase multi-component bio-reactive transport model was implemented by (Hagemann 2018) in the open-source DuMux (Flemisch et al. 2011) simulation toolkit for porous media flow. The underlying processes include the transport of reactants and products, consumption of specific components, and the related growth and decay of the microbial population, resulting in a bio-reactive transport model. The microbial kinetic parameters of methanogenic reactions are taken from the available literature. The simulation study covers different scenarios on conceptional field-scale models, studying the impact of well placement, injection rates, and gas compositions.\u0000 Due to a significant sensitivity of the simulation results to the bio-conversion kinetics, the field-specific conversion rates must be obtained. Thus, the Bio-UGS project is accompanied by laboratory experiments out of the frame of this paper.\u0000 Other parameters are rather a matter of design; in the present case of depleted gas fields, those parameters are coupled and can be chosen to convert fully hydrogen and carbon dioxide to methane. Especially the well spacing can be considered the main design parameter in the likely case of a given injection rate and gas composition.\u0000 This study extends the application of the previously developed code from a homogeneous-2D to the heterogeneous-3D case. The simulations mimic the co-injection of carbon dioxide and hydrogen from a 40 MW electrolysis.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80288434","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}
E. Saifullin, C. Yuan, M. V. Zvada, M. Varfolomeev, Shinar Kayratovna Shanbosinova, Dmitrii A. Zharkov, S. A. Nazarychev, Aleksei Olegovich Malakhov, R. N. Sagirov
Messoyakhskoye field, operated by Gazprom Neft, is currently experiencing gas channeling from gas cap in production wells because of strong heterogeneity. Foam for a long has been considered as a good candidate for gas blocking, (Svorstol I. et al., 1996), (Hanssen, J. E., & Dalland, M. 1994), (Aarra, M. G. et al., 1996). However, foam injection for gas blocking in injection well is different from that in production well, where it is necessary to selectively and long-term impact on gas-saturated highly permeable areas without affecting the phase permeability of oil in the reservoir. This paper provides detailed laboratory studies that show how to determine suitable foam systems for gas blocking in production well. For gas blocking in production well, a long half-life time is required to sustain stable foam because a continuous shear of surfactant solution/gas can't be achieved like in injection well. Therefore, reinforced foam by polymer is chosen. Four polymer stabilizers and five foam agents were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of solution, which not only decreases the foam rate, but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15-0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in core first increased and then deceased with foam quality (the ratio of gas volume to foam volume (gas + liquid). The optimal injection mode is co-injection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that gas-blocking ability of polymer reinforced foam is better in high-permeability cores, which is beneficial for blocking high permeability zone. It should be also noted that under a certain ratio of oil to foam solution (about lower than 1 to 1), the presence of oil slowly decreased foam rate with increasing oil volume, but significantly increased half -life time, which is favorable for foam treatment in production well. This work highlights the difference between foam injection for gas blocking in production well and injection well, and emphasizes the use of polymer reinforced foam. Moreover, this work shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering differ
Messoyakhskoye油田由Gazprom Neft运营，由于其非均质性很强，目前正在经历从生产井的气顶产生气窜的问题。长期以来，泡沫一直被认为是气体堵塞的良好候选者(Svorstol I. et al.， 1996)， (Hanssen, j.e.， & Dalland, M. 1994)， (Aarra, m.g.等人，1996)。但是，注气井注气泡沫封堵与生产井不同，需要在不影响储层油相渗透率的前提下，对含气饱和的高渗透区域进行选择性的、长期的影响。本文提供了详细的实验室研究，展示了如何确定适合生产井气堵的泡沫体系。对于生产井的气堵，由于表面活性剂溶液/气体不能像注水井那样连续剪切，因此需要较长的半衰期来维持稳定的泡沫。因此，选用聚合物增强泡沫。采用体积试验对4种聚合物稳定剂和5种泡沫剂进行了评价，通过比较泡沫速率和半衰期来确定合适的泡沫体系，从而确定了泡沫能力、泡沫稳定性和油的影响。此外，在油藏条件下进行了过滤实验，通过评估表观粘度、突破压力梯度、阻力系数和残余阻力系数来确定最佳注入方式。聚合物能显著提高半衰期(增加泡沫稳定性)，且聚合物浓度越高，半衰期越长。但同时，较高的聚合物浓度会增加溶液的初始粘度，这不仅降低了泡沫速率，而且增加了注射难度。因此，考虑到所有这些影响，确定了约0.15-0.2 wt%的最佳聚合物浓度。过滤实验表明，随着泡沫质量(气液比)的增加，岩心表观粘度先增大后减小。最佳的注入方式是表面活性剂/聚合物溶液与气体共注入，原位生成泡沫，最佳泡沫质量约为0.65。不同渗透率岩心的过滤实验表明，聚合物增强泡沫在高渗透岩心中的阻气能力较好，有利于封堵高渗透层。需要注意的是，在一定的油泡沫比下(约低于1比1)，随着油体积的增加，泡沫速率缓慢降低，但半衰期明显延长，有利于生产井的泡沫处理。这项工作强调了在生产井和注水井中注泡沫堵气的区别，并强调了聚合物增强泡沫的使用。此外，本文还提出了系统的实验方法，在考虑不同因素的情况下选择适合生产井气堵的泡沫体系，为设计中试应用提供了使用哪种发泡剂和聚合物稳定剂以及如何对其进行评估的指导。
{"title":"Laboratory Studies For Design of a Foam Pilot For Reducing Gas Channeling From Gas Cap in Production Well in Messoyakhskoye Field","authors":"E. Saifullin, C. Yuan, M. V. Zvada, M. Varfolomeev, Shinar Kayratovna Shanbosinova, Dmitrii A. Zharkov, S. A. Nazarychev, Aleksei Olegovich Malakhov, R. N. Sagirov","doi":"10.2118/206435-ms","DOIUrl":"https://doi.org/10.2118/206435-ms","url":null,"abstract":"\u0000 Messoyakhskoye field, operated by Gazprom Neft, is currently experiencing gas channeling from gas cap in production wells because of strong heterogeneity. Foam for a long has been considered as a good candidate for gas blocking, (Svorstol I. et al., 1996), (Hanssen, J. E., & Dalland, M. 1994), (Aarra, M. G. et al., 1996). However, foam injection for gas blocking in injection well is different from that in production well, where it is necessary to selectively and long-term impact on gas-saturated highly permeable areas without affecting the phase permeability of oil in the reservoir. This paper provides detailed laboratory studies that show how to determine suitable foam systems for gas blocking in production well.\u0000 For gas blocking in production well, a long half-life time is required to sustain stable foam because a continuous shear of surfactant solution/gas can't be achieved like in injection well. Therefore, reinforced foam by polymer is chosen. Four polymer stabilizers and five foam agents were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor.\u0000 Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of solution, which not only decreases the foam rate, but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15-0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in core first increased and then deceased with foam quality (the ratio of gas volume to foam volume (gas + liquid). The optimal injection mode is co-injection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that gas-blocking ability of polymer reinforced foam is better in high-permeability cores, which is beneficial for blocking high permeability zone. It should be also noted that under a certain ratio of oil to foam solution (about lower than 1 to 1), the presence of oil slowly decreased foam rate with increasing oil volume, but significantly increased half -life time, which is favorable for foam treatment in production well.\u0000 This work highlights the difference between foam injection for gas blocking in production well and injection well, and emphasizes the use of polymer reinforced foam. Moreover, this work shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering differ","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82812510","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}
Under the present conditions of oil and gas production, which are characterized by mature production fields and the focus shifted towards digitalization of production processes and use of machine learning (ML) models, the issues related to the improvement of accuracy and consistency of the well operation control data are becoming increasingly important. As a result, SPD has successfully implemented the project of using annular pressure sensors in combination with machine learning models to control the well annular pressure as part of the field development program compliance. Under the field development program, echosounder and telemetry system readings are typically used to control the annular pressure and the dynamic flowing level. Echosounders, however, are not designed as measuring instruments, the accuracy of their readings being low and making it impossible to reliably evaluate the well's dynamic flowing level and annular pressure, as well as to achieve the well's maximum potential, and the telemetry systems used to measure the pump intake pressure may go wrong. This manuscript describes the approach to the producer well annular pressure assessment based on the machine learning model data. The machine learning (ML) model is a function of the target variable (bottom-hole pressure), which is predicted on the basis of the actual data: static parameters (well schematic, pump design) and dynamic parameters (annular and line pressures, flowrate). The input parameter interpretation results in the most probable value of the target variable based on the historic data.
{"title":"Optimization of the Reservoir Management System and the ESP Operation Control Process by Means of Machine Learning on the Oilfields of Salym Petroleum Development N.V.","authors":"A. Musorina, Grigory Sergeyevich Ishimbayev","doi":"10.2118/206518-ms","DOIUrl":"https://doi.org/10.2118/206518-ms","url":null,"abstract":"\u0000 Under the present conditions of oil and gas production, which are characterized by mature production fields and the focus shifted towards digitalization of production processes and use of machine learning (ML) models, the issues related to the improvement of accuracy and consistency of the well operation control data are becoming increasingly important. As a result, SPD has successfully implemented the project of using annular pressure sensors in combination with machine learning models to control the well annular pressure as part of the field development program compliance.\u0000 Under the field development program, echosounder and telemetry system readings are typically used to control the annular pressure and the dynamic flowing level. Echosounders, however, are not designed as measuring instruments, the accuracy of their readings being low and making it impossible to reliably evaluate the well's dynamic flowing level and annular pressure, as well as to achieve the well's maximum potential, and the telemetry systems used to measure the pump intake pressure may go wrong.\u0000 This manuscript describes the approach to the producer well annular pressure assessment based on the machine learning model data. The machine learning (ML) model is a function of the target variable (bottom-hole pressure), which is predicted on the basis of the actual data: static parameters (well schematic, pump design) and dynamic parameters (annular and line pressures, flowrate). The input parameter interpretation results in the most probable value of the target variable based on the historic data.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82674662","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}
Currently, the standard approach to building a geomechanical model for analyzing wellbore stability involves taking into account only elastic deformations. This approach has shown its inconsistency in the design and drilling of wells passing through rocks with pronounced plastic properties. Such rocks are characterized by the fact that when the loads acting on them change, they demonstrate not only elastic, but also plastic (irreversible) deformations. Plastic deformations have an additional impact on the distribution of stresses in the rock of the near-wellbore zone on a qualitative and quantitative level. Since plastic deformations are not taken into account in the standard approach, in this case the results of the wellbore stability analysis are based on incorrectly calculated stresses acting in the rock. As a result, it can lead to misinterpretation of the model for analysis, suboptimal choice of trajectory, incorrect calculation of safe mud window and an incorrectly selected set of measures to reduce the risks of instability. The aim of this work is to demonstrate the advantages of the developed 3D elasto-plastic program for calculating the wellbore stability in comparison with the standard elastic method used in petroleum geomechanics. The central core of the work is the process of initialization of the elasto-plastic model according to the data of core tests and the subsequent validation of experimental and numerical loading curves. The developed 3D program is based on a modified Drucker-Prager model and implemented in a finite element formulation. 3D geomechanical model of wellbore stability allows describing deformation processes in the near-wellbore zone and includes the developed failure criteria. The paper shows a special approach to the determination of the mud window based on well logging data and core tests by taking into account the plastic behavior of rocks. An important result of this study is the determination of the possibility of expanding the mud window when taking into account the plastic criterion of rock failure.
{"title":"Influence of Rock Plastic Behavior on the Wellbore Stability","authors":"E. Grishko, A. Garavand, A. Cheremisin","doi":"10.2118/206557-ms","DOIUrl":"https://doi.org/10.2118/206557-ms","url":null,"abstract":"\u0000 Currently, the standard approach to building a geomechanical model for analyzing wellbore stability involves taking into account only elastic deformations. This approach has shown its inconsistency in the design and drilling of wells passing through rocks with pronounced plastic properties. Such rocks are characterized by the fact that when the loads acting on them change, they demonstrate not only elastic, but also plastic (irreversible) deformations. Plastic deformations have an additional impact on the distribution of stresses in the rock of the near-wellbore zone on a qualitative and quantitative level. Since plastic deformations are not taken into account in the standard approach, in this case the results of the wellbore stability analysis are based on incorrectly calculated stresses acting in the rock. As a result, it can lead to misinterpretation of the model for analysis, suboptimal choice of trajectory, incorrect calculation of safe mud window and an incorrectly selected set of measures to reduce the risks of instability.\u0000 The aim of this work is to demonstrate the advantages of the developed 3D elasto-plastic program for calculating the wellbore stability in comparison with the standard elastic method used in petroleum geomechanics. The central core of the work is the process of initialization of the elasto-plastic model according to the data of core tests and the subsequent validation of experimental and numerical loading curves.\u0000 The developed 3D program is based on a modified Drucker-Prager model and implemented in a finite element formulation. 3D geomechanical model of wellbore stability allows describing deformation processes in the near-wellbore zone and includes the developed failure criteria.\u0000 The paper shows a special approach to the determination of the mud window based on well logging data and core tests by taking into account the plastic behavior of rocks. An important result of this study is the determination of the possibility of expanding the mud window when taking into account the plastic criterion of rock failure.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84259065","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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