For the purpose of this work, the authors used an integrated approach to the modeling of in-situ combustion (ISC) including the results of laboratory studies and preliminary works, which significantly affect the choice of the method for implementing ISC and the results obtained in the process of modeling. The laboratory studies provided the data on the temperature range of the beginning of high-temperature oil oxidation, which is to be achieved during the modelling of the bottomhole zone heating. Based on the resulting injectivity profile, the reservoir distribution within the injection well zone in the geological model was updated. A high-permeability channel between the injection well and one of the production wells revealed during cold water injection explains the main oil production increment resulting from ISC and demonstrated by the reservoir simulation model. Based on the results of model runs for a more uniform distribution of the effect between producing wells, the best start-up time for the most reactive well was determined. Using dynamic modeling of in-situ combustion in a carbonate reservoir, the parameters of this technology implementation were found, and incremental oil production was estimated. For the first time, the ISC technology is planned for implementation in a carbonate reservoir with high-viscosity oil in Samara region. The developed integrated approach to the dynamic modeling of in-situ combustion, which considers both the laboratory studies and preparatory work data, enables the most accurately determination of the best ISC technological parameters and this technology contribution.
{"title":"Approach to Hydrodynamic Modeling of In-Situ Combustion in Carbonate Reservoir Based on the Results of Laboratory Studies and Preliminary Works for Pilot Test","authors":"K. Maksakov, N. V. Lesina, K. Schekoldin","doi":"10.2118/206546-ms","DOIUrl":"https://doi.org/10.2118/206546-ms","url":null,"abstract":"\u0000 For the purpose of this work, the authors used an integrated approach to the modeling of in-situ combustion (ISC) including the results of laboratory studies and preliminary works, which significantly affect the choice of the method for implementing ISC and the results obtained in the process of modeling.\u0000 The laboratory studies provided the data on the temperature range of the beginning of high-temperature oil oxidation, which is to be achieved during the modelling of the bottomhole zone heating. Based on the resulting injectivity profile, the reservoir distribution within the injection well zone in the geological model was updated. A high-permeability channel between the injection well and one of the production wells revealed during cold water injection explains the main oil production increment resulting from ISC and demonstrated by the reservoir simulation model. Based on the results of model runs for a more uniform distribution of the effect between producing wells, the best start-up time for the most reactive well was determined. Using dynamic modeling of in-situ combustion in a carbonate reservoir, the parameters of this technology implementation were found, and incremental oil production was estimated.\u0000 For the first time, the ISC technology is planned for implementation in a carbonate reservoir with high-viscosity oil in Samara region. The developed integrated approach to the dynamic modeling of in-situ combustion, which considers both the laboratory studies and preparatory work data, enables the most accurately determination of the best ISC technological parameters and this technology contribution.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90524571","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}
Information technologies have long been an integral part of our lives, and the oil and gas industry has also undergone natural IT evolution. Modern technologies have allowed to automate the basic processes and structure the existing order of work, but there are still unresolved problems, one of which is monitoring the full life cycle of drill pipes and predicting the accumulation of fatigue damage. In most cases, the failure of the drill pipes is associated with fatigue destruction, which begins with microcracks as a result of exposure to variable stresses during the construction of the well (drilling). Currently, there are no effective methods to control accumulated fatigue damage or residual durability of the pipe at a given level of stress. In this regard, a system is required for a more reliable assessment of the condition of the drill pipes, which will take into account the whole list of factors influencing the rate of accumulation of fatigue damage in the body of the pipe and will allow to calculate (predict) the accumulated fatigue of the drilling pipes, using data from drilling regimes and well parameters. Understanding the mechanism of accumulation of fatigue wear, which leads to the failure of drilling pipes, makes it possible to manage this process, significantly reduce the cost of maintenance of the drilling pipe fund and reduce incidents with drilling pipes.
{"title":"Innovative Approach to Analysis Drilling Tool Works","authors":"R. I. Gubaidullin","doi":"10.2118/206458-ms","DOIUrl":"https://doi.org/10.2118/206458-ms","url":null,"abstract":"\u0000 Information technologies have long been an integral part of our lives, and the oil and gas industry has also undergone natural IT evolution. Modern technologies have allowed to automate the basic processes and structure the existing order of work, but there are still unresolved problems, one of which is monitoring the full life cycle of drill pipes and predicting the accumulation of fatigue damage. In most cases, the failure of the drill pipes is associated with fatigue destruction, which begins with microcracks as a result of exposure to variable stresses during the construction of the well (drilling).\u0000 Currently, there are no effective methods to control accumulated fatigue damage or residual durability of the pipe at a given level of stress. In this regard, a system is required for a more reliable assessment of the condition of the drill pipes, which will take into account the whole list of factors influencing the rate of accumulation of fatigue damage in the body of the pipe and will allow to calculate (predict) the accumulated fatigue of the drilling pipes, using data from drilling regimes and well parameters.\u0000 Understanding the mechanism of accumulation of fatigue wear, which leads to the failure of drilling pipes, makes it possible to manage this process, significantly reduce the cost of maintenance of the drilling pipe fund and reduce incidents with drilling pipes.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 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":"75936400","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}
Mariia Kurianova, E. Birkle, T. Egorkina, S. Koltsov
The article considers the approaches to the G&G data interpretation used in the Branch Office of Gazprom International in Saint Petersburg (hereinafter referred to as "GPEPI") when studying the geology aspects of turbidite deposits. This approach is showcased on one of the Upper Miocene deposits of the Nam Con Son Basin in Vietnam, and a conclusion is drawn about the possibility of using this complex technique in the study of sand bodies of any genesis.
{"title":"Comprehensive Analysis of the Geological and Geophysical Data in the Study of the Upper Miocene Turbidite Systems of the Nam Con Son Basin, Vietnam","authors":"Mariia Kurianova, E. Birkle, T. Egorkina, S. Koltsov","doi":"10.2118/206549-ms","DOIUrl":"https://doi.org/10.2118/206549-ms","url":null,"abstract":"\u0000 The article considers the approaches to the G&G data interpretation used in the Branch Office of Gazprom International in Saint Petersburg (hereinafter referred to as \"GPEPI\") when studying the geology aspects of turbidite deposits. This approach is showcased on one of the Upper Miocene deposits of the Nam Con Son Basin in Vietnam, and a conclusion is drawn about the possibility of using this complex technique in the study of sand bodies of any genesis.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77247534","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 present work describes one of the key areas of research activity of the modern oil and gas scientific world: decarbonization and increasing the efficiency of the natural and associated gas usage which is a method for producing carbon black. The technology is characterized by relative simplicity of the technological process and a wide market for the resulting product. This method is also included in the list of BAT (BREFs, 2020). The article presents a techno-economic assessment of the proposed method of using gas, there is also a comparison with other existing methods.
{"title":"Techno-Economic Assessment of the Equipment for Production Carbon Black from APG","authors":"A. S. Dimitriev, A. A. Bandaletova","doi":"10.2118/206566-ms","DOIUrl":"https://doi.org/10.2118/206566-ms","url":null,"abstract":"\u0000 The present work describes one of the key areas of research activity of the modern oil and gas scientific world: decarbonization and increasing the efficiency of the natural and associated gas usage which is a method for producing carbon black. The technology is characterized by relative simplicity of the technological process and a wide market for the resulting product. This method is also included in the list of BAT (BREFs, 2020). The article presents a techno-economic assessment of the proposed method of using gas, there is also a comparison with other existing methods.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77247540","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. V. Syundyukov, G. Khabibullin, Alexander Stanislavovich Trofimchuk, Denis Radikovich Shaikhatdarov, D. K. Sagitov
This paper presents a method for predicting the development of Auto-HF (crack) in injection wells of the reservoir pressure maintenance system during the development of low-permeable reservoirs, in order to ensure the optimal front of oil displacement by water by regulating the bottom-hole pressure of injection wells based on the derived dependence of the half-length of the Auto-HF (crack).
{"title":"Flood Control Method in Fields with Hard-To-Recover Reserves","authors":"A. V. Syundyukov, G. Khabibullin, Alexander Stanislavovich Trofimchuk, Denis Radikovich Shaikhatdarov, D. K. Sagitov","doi":"10.2118/206408-ms","DOIUrl":"https://doi.org/10.2118/206408-ms","url":null,"abstract":"\u0000 This paper presents a method for predicting the development of Auto-HF (crack) in injection wells of the reservoir pressure maintenance system during the development of low-permeable reservoirs, in order to ensure the optimal front of oil displacement by water by regulating the bottom-hole pressure of injection wells based on the derived dependence of the half-length of the Auto-HF (crack).","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76868139","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}
Andrei Konstantinovich Maltsev, N. Kudlaeva, A. Aslanyan, V. Krichevsky, D. Gulyaev, L. Surmasheva, Viktoria Vitalievna Solovyeva
The main goal of the pilot job is to assess the risks of production by horizontal wells and multilateral wells with a close gas cap above and water layers beneath the main formation. The objectives are to monitor the total producing length of the wells using temperature and pressure surveillance. The results of monitoring were analyzed at different stages of development. An analysis was carried out by combining pressure and temperature data obtained while monitoring the production of multilateral wells. The well properties were determined using RTA and PTA. To assess the inflow profile, distributed temperature sensors in the wells were analyzed for the entire period of appraisal production. A feature of the research was the low contrast of temperature anomalies associated with fluid inflow. In addition, it was also revealed that the DTS absolute readings at the depth of the formation were affected by surface temperature, which required corrections and the use of relative readings in the calculations instead of absolute ones. The main feature of the pressure analysis was the short period of production. With such well completion geometry and reservoir properties of the layer, the radial flow could not be achieved during the whole test period. Despite these limitations, the dynamics of the total producing length of the well was determined. The initial value of the producing length was about 70% of the drilled length, then there is a slight decrease after 7 to 10 months of well production. By analyzing the fiber-optic temperature profile, an inflow profile was assessed. Based on the analysis of changes in relative temperature anomalies, the shares of inflow from the sidetracks were estimated. Several memory temperature / pressure gauges set along the horizontal section were used as an additional data source to monitor well parameters during the whole period of production. The difference in their readings was due to, among other things, the average flow rate in the section between the sensors, which made it possible to give an independent assessment of the inflow profile. Based on the results of the job performed, a number of risks and uncertainties were removed, including information on the total flowing horizontal length dynamics, which is a valuable input for full-field development planning. In addition, an express method of DTS data analysis has been developed for assessing the wellbore producing length without significant temperature changes associated with intervals of inflow.
{"title":"Evaluating Efficiency of Multilateral Producing Wells in Bottom Water-Drive Reservoir with a Gas Cap by Distributed Fiber-Optic Sensors and Continuous Pressure Monitoring","authors":"Andrei Konstantinovich Maltsev, N. Kudlaeva, A. Aslanyan, V. Krichevsky, D. Gulyaev, L. Surmasheva, Viktoria Vitalievna Solovyeva","doi":"10.2118/206485-ms","DOIUrl":"https://doi.org/10.2118/206485-ms","url":null,"abstract":"\u0000 The main goal of the pilot job is to assess the risks of production by horizontal wells and multilateral wells with a close gas cap above and water layers beneath the main formation. The objectives are to monitor the total producing length of the wells using temperature and pressure surveillance. The results of monitoring were analyzed at different stages of development.\u0000 An analysis was carried out by combining pressure and temperature data obtained while monitoring the production of multilateral wells. The well properties were determined using RTA and PTA.\u0000 To assess the inflow profile, distributed temperature sensors in the wells were analyzed for the entire period of appraisal production. A feature of the research was the low contrast of temperature anomalies associated with fluid inflow. In addition, it was also revealed that the DTS absolute readings at the depth of the formation were affected by surface temperature, which required corrections and the use of relative readings in the calculations instead of absolute ones.\u0000 The main feature of the pressure analysis was the short period of production. With such well completion geometry and reservoir properties of the layer, the radial flow could not be achieved during the whole test period. Despite these limitations, the dynamics of the total producing length of the well was determined. The initial value of the producing length was about 70% of the drilled length, then there is a slight decrease after 7 to 10 months of well production.\u0000 By analyzing the fiber-optic temperature profile, an inflow profile was assessed. Based on the analysis of changes in relative temperature anomalies, the shares of inflow from the sidetracks were estimated.\u0000 Several memory temperature / pressure gauges set along the horizontal section were used as an additional data source to monitor well parameters during the whole period of production. The difference in their readings was due to, among other things, the average flow rate in the section between the sensors, which made it possible to give an independent assessment of the inflow profile.\u0000 Based on the results of the job performed, a number of risks and uncertainties were removed, including information on the total flowing horizontal length dynamics, which is a valuable input for full-field development planning. In addition, an express method of DTS data analysis has been developed for assessing the wellbore producing length without significant temperature changes associated with intervals of inflow.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73091538","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. Samolovov, A. Varavva, Vitalij Olegovich Polyakov, Ekaterina Evgenevna Sandalova
The study proposes an analytical method for calculating the productivity of horizontal wells in a line-drive development pattern in fields with oil rims. The paper presents an analysis of existing techniques and compares them with the results of detailed numerical experiments. It also shows the limited applicability of existing techniques. On the basis of the obtained solution of a single-phase flow equation for a line-drive pattern of horizontal wells, an analytical formula was obtained which more accurately describes the productivity of wells beyond the limits of applicability of existing methods. The resulting formula is in good agreement with the results of a detailed numerical experiment.
{"title":"The Productivity of Horizontal Wells in an In-Line Development System in Fields with Oil Rims","authors":"D. Samolovov, A. Varavva, Vitalij Olegovich Polyakov, Ekaterina Evgenevna Sandalova","doi":"10.2118/206573-ms","DOIUrl":"https://doi.org/10.2118/206573-ms","url":null,"abstract":"\u0000 The study proposes an analytical method for calculating the productivity of horizontal wells in a line-drive development pattern in fields with oil rims. The paper presents an analysis of existing techniques and compares them with the results of detailed numerical experiments. It also shows the limited applicability of existing techniques. On the basis of the obtained solution of a single-phase flow equation for a line-drive pattern of horizontal wells, an analytical formula was obtained which more accurately describes the productivity of wells beyond the limits of applicability of existing methods. The resulting formula is in good agreement with the results of a detailed numerical experiment.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85774855","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}
T. Yushchenko, E. V. Demin, R. Khabibullin, K. S. Sorokin, Mikhail Viktorovich Khachaturyan, I. V. Baykov, R. I. Gatin
Wells with extended horizontal wellbore (HW) drilling with multistage hydraulic fracturing (MHF) is necessary for commercial oil production from Bazhenov formation (Vashkevich et al., 2015; Strizhnev, 2019). Today the maximum HW length for Bazhenov formation wells is 1500 m (Strizhnev, 2019, Korobitsyn et al., 2020). In international practice the maximum HW length for shale oil production is around 3000-400 m (Rodionova et al., 2019). Pump Down Perforator (PDP) technology is used for MHF: a liner is run in hole and cemented, then perforation and hydraulic fracturing (HF) are successively performed by stages at equal distances from the end to the beginning of HW to create a branched system of fractures in Bazhenov formation. Performed HF stages are isolated with special packer plugs (insoluble blind, dissolvable blind, insoluble with seat for dissolvable ball or dissolvable with seat for dissolvable ball)) (Mingazov et al., 2020). Consequently, the fluid inflow into the well is occurred along whole HW and the flow rate increases from monotonically from the end to the beginning of HW and has maximum value at last HF stage. The numbers of HF stages are about 24-30 (number of perforating clusters - 100) at one well in Russia and 50 in the world (Alzahabi et al., 2019). One of important parameter during HF is the speed of HF fluid injection into the formation. Tubing outer diameters 114-140 mm. are used in HW to increase the injection rate and reduce friction losses in the well. The flow rate of HF fluid in this case reach to 14-16 m3/min (Ogneva et al., 2020; Astafiev et al., 2015). Monobore wells construction is planned to use with outer diameter 140 mm. A stinger is used as sealing element between tubing and liner to minimizing risk of HF liquids leaks into the annulus (Astafiev et al., 2015). As a result, the inner well diameter from wellhead to bottomhole is around constant in the process of MHF. The pressure in the hydraulic fractures and the collector near fractures after MHF is highly exceeded the initial reservoir pressure. Hence wellhead pressure after MHF in water filled well is about 100-150 bar (Jing Wang et al., 2021). This fact significantly limits downhole well operations because of requires killing (tubing change, let down ESP, etc.). These works are required heavy well killing fluid because of high overpressure. It is undesirable because of it can reduce the fracture conductivity, worse well bottom zone properties and reduce well productivity. Therefore, the well is working at flowing mode in initial period usually until the reservoir pressure in the drainage area is decreased at the hydrostatic level or below (Jing Wang et al., 2021). After that the well can be killing using technical water with a density of 1.01 – 1.07 g/sm3 (the use of well-killing fluid with a density higher than 1.1 g/sm3 is undesirable). The possibility of well flowing working depends on properties of collector and reservoir fluid: High gas-oil ratio (GOR)
对于Bazhenov地层的商业采油来说，采用扩展水平井眼(HW)钻井和多级水力压裂(MHF)是必要的(Vashkevich等，2015;Strizhnev, 2019)。目前Bazhenov地层井的最大井长为1500米(Strizhnev, 2019, Korobitsyn等，2020)。在国际实践中，页岩油开采的最大HW长度约为3000-400 m (Rodionova et al.， 2019)。泵下射孔器(PDP)技术用于MHF:将尾管下入井中并固井，然后依次进行射孔和水力压裂(HF)，从HW的末端到开始，以相同的距离分段进行，在Bazhenov地层中形成分支裂缝系统。已完成的HF级使用特殊封隔器桥塞(不溶性盲塞、可溶性盲塞、可溶球不溶性阀座或可溶球可溶阀座)进行隔离(Mingazov等，2020)。因此，井内流体沿整个HF阶段流入，从HF阶段结束到HF阶段开始，流量呈单调递增趋势，在HF阶段末达到最大值。俄罗斯一口井的高频级数约为24-30级(射孔簇数量为100个)，世界上为50级(Alzahabi等人，2019)。高频流体注入地层的速度是高频流体注入地层的一个重要参数。油管外径114-140 mm用于HW，以提高注入速度并减少井中的摩擦损失。在这种情况下HF流体的流量达到14-16 m3/min (Ogneva et al.， 2020;Astafiev et al.， 2015)。计划采用外径140mm的单孔井施工。推力杆用作油管和尾管之间的密封元件，以最大限度地降低HF液体泄漏到环空的风险(Astafiev等，2015)。因此，在MHF过程中，从井口到井底的内井直径基本保持恒定。MHF后水力裂缝内和裂缝附近集热器内的压力大大超过了初始储层压力。因此，充水井中MHF后的井口压力约为100-150 bar (Jing Wang et al.， 2021)。由于需要压井(换油管、下放电潜泵等)，这极大地限制了井下作业。由于高压，这些作业需要使用重型压井液。这是不可取的，因为它会降低裂缝导流能力，使井底层性能变差，降低油井产能。因此，井在初始阶段通常处于流动状态，直到泄放区储层压力降至静水水平或以下(Jing Wang et al.， 2021)。之后，可以使用密度为1.01 - 1.07 g/sm3的技术水进行压井(不希望使用密度高于1.1 g/sm3的压井液)。井筒流动工作的可能性取决于捕集剂和储层流体的性质:高气油比(GOR)和储层导电性有助于井筒流动，直到储层压力低于静水压力。
{"title":"Operation Features of Wells with an Extended Horizontal Wellbore and Multistage Hydraulic Fracturing Operation in Bazhenov Formation","authors":"T. Yushchenko, E. V. Demin, R. Khabibullin, K. S. Sorokin, Mikhail Viktorovich Khachaturyan, I. V. Baykov, R. I. Gatin","doi":"10.2118/206482-ms","DOIUrl":"https://doi.org/10.2118/206482-ms","url":null,"abstract":"\u0000 Wells with extended horizontal wellbore (HW) drilling with multistage hydraulic fracturing (MHF) is necessary for commercial oil production from Bazhenov formation (Vashkevich et al., 2015; Strizhnev, 2019). Today the maximum HW length for Bazhenov formation wells is 1500 m (Strizhnev, 2019, Korobitsyn et al., 2020). In international practice the maximum HW length for shale oil production is around 3000-400 m (Rodionova et al., 2019). Pump Down Perforator (PDP) technology is used for MHF: a liner is run in hole and cemented, then perforation and hydraulic fracturing (HF) are successively performed by stages at equal distances from the end to the beginning of HW to create a branched system of fractures in Bazhenov formation. Performed HF stages are isolated with special packer plugs (insoluble blind, dissolvable blind, insoluble with seat for dissolvable ball or dissolvable with seat for dissolvable ball)) (Mingazov et al., 2020). Consequently, the fluid inflow into the well is occurred along whole HW and the flow rate increases from monotonically from the end to the beginning of HW and has maximum value at last HF stage. The numbers of HF stages are about 24-30 (number of perforating clusters - 100) at one well in Russia and 50 in the world (Alzahabi et al., 2019).\u0000 One of important parameter during HF is the speed of HF fluid injection into the formation. Tubing outer diameters 114-140 mm. are used in HW to increase the injection rate and reduce friction losses in the well. The flow rate of HF fluid in this case reach to 14-16 m3/min (Ogneva et al., 2020; Astafiev et al., 2015). Monobore wells construction is planned to use with outer diameter 140 mm. A stinger is used as sealing element between tubing and liner to minimizing risk of HF liquids leaks into the annulus (Astafiev et al., 2015). As a result, the inner well diameter from wellhead to bottomhole is around constant in the process of MHF.\u0000 The pressure in the hydraulic fractures and the collector near fractures after MHF is highly exceeded the initial reservoir pressure. Hence wellhead pressure after MHF in water filled well is about 100-150 bar (Jing Wang et al., 2021). This fact significantly limits downhole well operations because of requires killing (tubing change, let down ESP, etc.). These works are required heavy well killing fluid because of high overpressure. It is undesirable because of it can reduce the fracture conductivity, worse well bottom zone properties and reduce well productivity. Therefore, the well is working at flowing mode in initial period usually until the reservoir pressure in the drainage area is decreased at the hydrostatic level or below (Jing Wang et al., 2021). After that the well can be killing using technical water with a density of 1.01 – 1.07 g/sm3 (the use of well-killing fluid with a density higher than 1.1 g/sm3 is undesirable). The possibility of well flowing working depends on properties of collector and reservoir fluid: High gas-oil ratio (GOR) ","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"202 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73212182","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. Lobanov, S. Fedorovskiy, I. Promzelev, Y. Tikhomirov, M. Zvonkov, V. Kovalenko, D. Kuporosov, A. Bastrakov, V. Nartymov, A. Harisov, Ivan Alexandrovich Struchkov, N. Pleshanov, S. Makarov, Artem Sergeevich Frolov
The services and downhole sampling technologies market in Russia is in deep stagnation. The objective conditions have emerged, wherein the responsibility and leadership in the development and recovery of this area is a prerogative task of major oil and gas companies, rather than the equipment manufacturers. The paper shares the authors’ experience in the development, pilot testing and implementation of novel regulatory and technical approaches and technologies of sampling, transportation, field, end-to-end and laboratory assessment of samples quality in PJSC «Gazprom Neft».
{"title":"End-to-End Quality Control of Downhole Samples from the Sampling Point to the Laboratory Unit: This is Possible and Necessary","authors":"A. Lobanov, S. Fedorovskiy, I. Promzelev, Y. Tikhomirov, M. Zvonkov, V. Kovalenko, D. Kuporosov, A. Bastrakov, V. Nartymov, A. Harisov, Ivan Alexandrovich Struchkov, N. Pleshanov, S. Makarov, Artem Sergeevich Frolov","doi":"10.2118/206487-ms","DOIUrl":"https://doi.org/10.2118/206487-ms","url":null,"abstract":"\u0000 The services and downhole sampling technologies market in Russia is in deep stagnation. The objective conditions have emerged, wherein the responsibility and leadership in the development and recovery of this area is a prerogative task of major oil and gas companies, rather than the equipment manufacturers. The paper shares the authors’ experience in the development, pilot testing and implementation of novel regulatory and technical approaches and technologies of sampling, transportation, field, end-to-end and laboratory assessment of samples quality in PJSC «Gazprom Neft».","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"105 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76353566","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}
Elena Descubes, S. Yessalina, Amir Kuvanyshev, A. Zhelezova, D. Shaikhina, M. Chertenkov, Andrey Valeryevich Barannikov
An unexpected raise of hydrogen sulfide levels during development of several gas condensate fields in Southwestern Gissar, producing from naturally fractured carbonate reservoirs, observed within a year, lead to necessity of full scale comprehensive investigation. For planning of effective mitigation strategy important questions related to the reasons of hydrogen sulfide level growth and prediction of its further behavior have been addressed in the present study. The entire investigation process encompassed both theoretical and practical parts. Theoretical part covered evaluation of sour gas sources that was crucial in respect to selection of conceptual methodology for predictions. All possible contributing sources including primary and secondary have been investigated to discern the causes and consequences of hydrogen sulfide occurrence. Practical component of the study employed cut to edge technologies tested and implemented in reservoir simulation. Based on conceptual constraints with the use of existing field data, interpretation results and regional knowledge basin and 3D static models with fracture network have been developed. Obtained modeling results have been integrated into compositional model, allowing to predict with applied uncertainty analyses further H2S content change during field development.
{"title":"Prediction of Dynamical Changes Hydrogen Sulfide Concentration During South-West Gissar Gas-Condensate Fields Development","authors":"Elena Descubes, S. Yessalina, Amir Kuvanyshev, A. Zhelezova, D. Shaikhina, M. Chertenkov, Andrey Valeryevich Barannikov","doi":"10.2118/206577-ms","DOIUrl":"https://doi.org/10.2118/206577-ms","url":null,"abstract":"\u0000 An unexpected raise of hydrogen sulfide levels during development of several gas condensate fields in Southwestern Gissar, producing from naturally fractured carbonate reservoirs, observed within a year, lead to necessity of full scale comprehensive investigation. For planning of effective mitigation strategy important questions related to the reasons of hydrogen sulfide level growth and prediction of its further behavior have been addressed in the present study.\u0000 The entire investigation process encompassed both theoretical and practical parts. Theoretical part covered evaluation of sour gas sources that was crucial in respect to selection of conceptual methodology for predictions. All possible contributing sources including primary and secondary have been investigated to discern the causes and consequences of hydrogen sulfide occurrence. Practical component of the study employed cut to edge technologies tested and implemented in reservoir simulation.\u0000 Based on conceptual constraints with the use of existing field data, interpretation results and regional knowledge basin and 3D static models with fracture network have been developed. Obtained modeling results have been integrated into compositional model, allowing to predict with applied uncertainty analyses further H2S content change during field development.","PeriodicalId":11177,"journal":{"name":"Day 4 Fri, October 15, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80911784","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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