Oksana Vasilievna Kokareva, Y. Miryasova, T. A. Alekseeva
With the advent of the equipment for full well logging suite in the horizontal wells, it became possible to evaluate the reservoir's quantitative parameters. However, the original curves are mainly used for this purpose, which leads to significant errors, in particular due to the significant influence of nearby reservoirs on the tools readings in the penetrated deposits. There is a need to discuss the current issues of interpretation in directional, horizontal and multi-lateral wells with the experts. 3DP module in the downhole software platform* allows to evaluate the overall influence of geometric effects, as well as to adjust logging curves for the influence of several reservoirs on the logging tools responses, which are not still taken into account by conventional methods when processing. The modeled density image is especially useful for confirming the model geometry, updating the local dip angle, and identifying areas, where additional features, such as thin layers, are to be added. The accounting for density and neutron porosity for layers in the petrophysical analysis increases the efficiency of calculating clay volume and porosity, which affects the saturation. The authors also proposed a methodology for assessing share of sand component based on RHOB image. Further accounting of NTG, for the correct assessment of the reservoir properties in a heterogeneous reservoir, followed by the data accounting in the geological model. The results obtained in the course of the work allowed to apply the spatial interpretation of horizontal well in geological modeling, as well as to improve the interpretation algorithm.
{"title":"Integrating Horizontal Wellbores When Building a Geological Model of an Offshore Field","authors":"Oksana Vasilievna Kokareva, Y. Miryasova, T. A. Alekseeva","doi":"10.2118/206601-ms","DOIUrl":"https://doi.org/10.2118/206601-ms","url":null,"abstract":"\u0000 With the advent of the equipment for full well logging suite in the horizontal wells, it became possible to evaluate the reservoir's quantitative parameters. However, the original curves are mainly used for this purpose, which leads to significant errors, in particular due to the significant influence of nearby reservoirs on the tools readings in the penetrated deposits.\u0000 There is a need to discuss the current issues of interpretation in directional, horizontal and multi-lateral wells with the experts.\u0000 3DP module in the downhole software platform* allows to evaluate the overall influence of geometric effects, as well as to adjust logging curves for the influence of several reservoirs on the logging tools responses, which are not still taken into account by conventional methods when processing.\u0000 The modeled density image is especially useful for confirming the model geometry, updating the local dip angle, and identifying areas, where additional features, such as thin layers, are to be added. The accounting for density and neutron porosity for layers in the petrophysical analysis increases the efficiency of calculating clay volume and porosity, which affects the saturation.\u0000 The authors also proposed a methodology for assessing share of sand component based on RHOB image. Further accounting of NTG, for the correct assessment of the reservoir properties in a heterogeneous reservoir, followed by the data accounting in the geological model.\u0000 The results obtained in the course of the work allowed to apply the spatial interpretation of horizontal well in geological modeling, as well as to improve the interpretation algorithm.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 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":"83522417","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. Chuprakov, L. Belyakova, I. Glaznev, A. Peshcherenko
We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.
{"title":"High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs","authors":"D. Chuprakov, L. Belyakova, I. Glaznev, A. Peshcherenko","doi":"10.2118/206654-ms","DOIUrl":"https://doi.org/10.2118/206654-ms","url":null,"abstract":"\u0000 We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy.\u0000 We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life.\u0000 We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84841522","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. Zavyalov, I. Yazykov, M. Nukhaev, K. Rymarenko, S. Grishenko, A. Golubtsov, Galymzhan Aitkaliev, V. Kabanov
This paper is aimed at the mobile gas-lift unit installation workup to shift the wells of the conductor platform of the Yu. Korchagin field to mechanized extraction instead of constructing a gas lift pipeline. The paper presents all the stages of this technology implementation, from conceptual design, engineering calculations, to the economic feasibility study, implementation and operation of this unit. During the operation of the wells of the conductor platform at the Yu. Korchagin field, the following problem occurred: a gas-lift gas pipeline was not constructed from the offshore ice-resistant fixed platform to the conductor platform, as they wanted to shift the wells to the mechanized extraction method (artificial lift). An alternative option to provide gas-lift gas to the wells of the conductor platform is to install a mobile gas-lift unit directly on an unmanned platform. This mobile gas-lift unit will be a compact separator of a gas-liquid mixture from a donor well, and it will pipe a separated gas-lift gas supply system with control and flow metering sets into the production wells. This system enables a shift of the wells of an unmanned conductor platform to a compressor-less gas-lift operation and a remote regulation of production and control over the wells operation.
{"title":"Development and Implementation of the Technology of a Mobile Gas-Lift Complex For Transferring Wells of the Block-Conductor of the Field Named After Yu. Korchagin For Artificial Lift","authors":"A. Zavyalov, I. Yazykov, M. Nukhaev, K. Rymarenko, S. Grishenko, A. Golubtsov, Galymzhan Aitkaliev, V. Kabanov","doi":"10.2118/206471-ms","DOIUrl":"https://doi.org/10.2118/206471-ms","url":null,"abstract":"\u0000 This paper is aimed at the mobile gas-lift unit installation workup to shift the wells of the conductor platform of the Yu. Korchagin field to mechanized extraction instead of constructing a gas lift pipeline. The paper presents all the stages of this technology implementation, from conceptual design, engineering calculations, to the economic feasibility study, implementation and operation of this unit.\u0000 During the operation of the wells of the conductor platform at the Yu. Korchagin field, the following problem occurred: a gas-lift gas pipeline was not constructed from the offshore ice-resistant fixed platform to the conductor platform, as they wanted to shift the wells to the mechanized extraction method (artificial lift). An alternative option to provide gas-lift gas to the wells of the conductor platform is to install a mobile gas-lift unit directly on an unmanned platform.\u0000 This mobile gas-lift unit will be a compact separator of a gas-liquid mixture from a donor well, and it will pipe a separated gas-lift gas supply system with control and flow metering sets into the production wells. This system enables a shift of the wells of an unmanned conductor platform to a compressor-less gas-lift operation and a remote regulation of production and control over the wells operation.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88245372","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. Koplik, Semen Sergeevich Kudrya, Denis Zolnikov, Rustam Albertovich Koltsov, A. Kovalevskiy
The recently developed Samotlor 2020 campaign includes a requirement to shift the Frac design to synthetic gelling agent (gellant) which would increase production, keep the reservoir clean and also reduce both capital and operational costs for each stage Frac stage (no need to heat up the water, an option to use the well water, no requirement to miniFrac performance, etc.). The key difference between guar-based gels and synthetic gels is a lower viscosity rating that results in a significant increase in the fracture length and an improved ability to transport high concentration of proppant due to its thixotropic properties (the ability of a substance to lower its viscosity as a result of a mechanical impact and grow its viscosity when still). When gel is destroyed throughout the fracture after the Frac is completed the synthetic option allows for a cleaner fracture and helps remove all residual matter from the fracture. Another important consideration is that guar shipments from India make Russian oil vulnerable to price, foreign exchange and availability fluctuations. If guar crops experience a bad year or Indian farmers determine that the market should be refocused on cotton or other areas (i.e. not guar), the guar prices in Russian would likely skyrocket. The authors worked as a team to come up with a list of clear recommendations to develop both new and existing wells for Lower Cretaceous collectors of the Vartovsk and Megion suites such as AV1 (1-2) and BV8(0) to increase production and reduce capital costs. We have determined that Frac fluids based on synthetic modified polyacrylamide start to come to the front and hold a leading position in the area of production stimulation as previously happened to other effective methods such as polymer water flooding, drilling and cementing applications.
{"title":"Experience in Low Viscosity Guar-Free Fracturing Fluid Under Samotlor Field Conditions","authors":"A. Koplik, Semen Sergeevich Kudrya, Denis Zolnikov, Rustam Albertovich Koltsov, A. Kovalevskiy","doi":"10.2118/206653-ms","DOIUrl":"https://doi.org/10.2118/206653-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The recently developed Samotlor 2020 campaign includes a requirement to shift the Frac design to synthetic gelling agent (gellant) which would increase production, keep the reservoir clean and also reduce both capital and operational costs for each stage Frac stage (no need to heat up the water, an option to use the well water, no requirement to miniFrac performance, etc.). The key difference between guar-based gels and synthetic gels is a lower viscosity rating that results in a significant increase in the fracture length and an improved ability to transport high concentration of proppant due to its thixotropic properties (the ability of a substance to lower its viscosity as a result of a mechanical impact and grow its viscosity when still). When gel is destroyed throughout the fracture after the Frac is completed the synthetic option allows for a cleaner fracture and helps remove all residual matter from the fracture. Another important consideration is that guar shipments from India make Russian oil vulnerable to price, foreign exchange and availability fluctuations. If guar crops experience a bad year or Indian farmers determine that the market should be refocused on cotton or other areas (i.e. not guar), the guar prices in Russian would likely skyrocket.\u0000 The authors worked as a team to come up with a list of clear recommendations to develop both new and existing wells for Lower Cretaceous collectors of the Vartovsk and Megion suites such as AV1 (1-2) and BV8(0) to increase production and reduce capital costs. We have determined that Frac fluids based on synthetic modified polyacrylamide start to come to the front and hold a leading position in the area of production stimulation as previously happened to other effective methods such as polymer water flooding, drilling and cementing applications.\u0000","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"125 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91443447","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. Ivanov, D. Korobkov, A. Sidorenkov, I. Varfolomeev, M. Stukan
Nowadays acidizing became one of the most common approaches used to increase the hydrocarbons production from carbonate reservoirs. An acid solution injected under pressures below the formation fracture pressures dissolves the rock matrix and, thus, facilitates the fluid flow. However, the overall treatment efficiency is crucially dependent on the acid composition and injection scenario, since the different dissolution patterns are created depending on the effective reaction rate (i.e. acid composition and matrix mineralogy) of the reactive fluid and the fluid injection rate. At slow injection rates, when the acid is spent before penetrating deep into the rock, the face dissolution scenario is observed. On the other hand, fast injection results in uniform distribution of the acid along the treatment zone and similar uniform dissolution of the matrix. The best result from production improvement point of view is achieved when the acid creates a set of thin channels - the so-called wormholes. This optimum regime corresponds to the minimum in the pore volume to breakthrough (PVBT) dependence on injection rate (Fredd, 1998; Zhang, 2021). Where PVBT is defined as the amount of treatment fluid (measured in core pore volumes) required to be injected before the appearance of macroscopic flow channel linking the opposite faces of the core. Thus, since the optimal acid composition and the injection rate are determined by geology and lithology of the reservoir, to achieve the best effect, each treatment should be preceded by experiments on representative rock samples. In addition to that, the parameters to be optimized for a typical acidizing job also include the sequence of injected fluids and the amount of the fluid to be injected (Yudin A., 2021), which requires an extensive laboratory study. Unfortunately, the amount of the core material available is usually not sufficient for such a comprehensive laboratory analysis. Moreover, the destructive nature of acidizing experiments imposes the fundamental limitation: experiments are performed on different core samples, which makes the results less conclusive.
目前，酸化已成为提高碳酸盐岩储层油气产量的最常用方法之一。在低于地层破裂压力的压力下注入酸溶液会溶解岩石基质，从而促进流体流动。然而，整体处理效率主要取决于酸成分和注入情况，因为不同的溶解模式取决于反应流体的有效反应速率(即酸成分和基质矿物学)和流体注入速率。在注入速度较慢的情况下，当酸在深入岩石之前耗尽时，观察到工作面溶解情况。另一方面，快速注入导致酸沿处理区均匀分布，并且基体的溶解也同样均匀。从提高产量的角度来看，最好的结果是当酸产生一组薄通道时，即所谓的虫洞。这种最佳状态对应于孔隙体积与突破(PVBT)对注入速率的最小依赖(Fredd, 1998;张,2021)。其中PVBT定义为在连接岩心相对面的宏观流动通道出现之前需要注入的处理液量(以岩心孔隙体积测量)。因此，由于储层的地质和岩性决定了最佳的酸成分和注入速度，为了达到最佳效果，每次处理前都要对有代表性的岩石样品进行实验。除此之外，典型酸化作业需要优化的参数还包括注入流体的顺序和注入流体的量(Yudin a .， 2021)，这需要进行广泛的实验室研究。不幸的是，可用的堆芯材料的数量通常不足以进行如此全面的实验室分析。此外，酸化实验的破坏性给实验带来了根本性的限制:实验是在不同的岩心样品上进行的，这使得结果不那么确凿。
{"title":"Digital Rock Extension of Laboratory Core Test Results for Acid Treatment Optimization","authors":"E. Ivanov, D. Korobkov, A. Sidorenkov, I. Varfolomeev, M. Stukan","doi":"10.2118/206591-ms","DOIUrl":"https://doi.org/10.2118/206591-ms","url":null,"abstract":"\u0000 Nowadays acidizing became one of the most common approaches used to increase the hydrocarbons production from carbonate reservoirs. An acid solution injected under pressures below the formation fracture pressures dissolves the rock matrix and, thus, facilitates the fluid flow.\u0000 However, the overall treatment efficiency is crucially dependent on the acid composition and injection scenario, since the different dissolution patterns are created depending on the effective reaction rate (i.e. acid composition and matrix mineralogy) of the reactive fluid and the fluid injection rate. At slow injection rates, when the acid is spent before penetrating deep into the rock, the face dissolution scenario is observed. On the other hand, fast injection results in uniform distribution of the acid along the treatment zone and similar uniform dissolution of the matrix. The best result from production improvement point of view is achieved when the acid creates a set of thin channels - the so-called wormholes. This optimum regime corresponds to the minimum in the pore volume to breakthrough (PVBT) dependence on injection rate (Fredd, 1998; Zhang, 2021). Where PVBT is defined as the amount of treatment fluid (measured in core pore volumes) required to be injected before the appearance of macroscopic flow channel linking the opposite faces of the core. Thus, since the optimal acid composition and the injection rate are determined by geology and lithology of the reservoir, to achieve the best effect, each treatment should be preceded by experiments on representative rock samples.\u0000 In addition to that, the parameters to be optimized for a typical acidizing job also include the sequence of injected fluids and the amount of the fluid to be injected (Yudin A., 2021), which requires an extensive laboratory study. Unfortunately, the amount of the core material available is usually not sufficient for such a comprehensive laboratory analysis. Moreover, the destructive nature of acidizing experiments imposes the fundamental limitation: experiments are performed on different core samples, which makes the results less conclusive.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87151303","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 article describes a method for developing low-permeability reservoirs using horizontal wells with multi-stage hydraulic fracturing. The effectiveness of the new method lies in protecting the horizontal part of the production well by drilling it through a non-reservoir plastic reservoir adjacent directly to the target reservoir. The paper considers various implementations of the technology and estimates the increase in oil recovery factor for each of them based on the results of hydrodynamic modeling. The risks associated with the implementation of the technology are considered. Methods for their reduction are proposed.
{"title":"The Development Method of Low-Permeability and Ultra-Low-Permeability Reservoirs by Waterflooding","authors":"A. Gimazov, Ildar Shamilevich Bazyrov","doi":"10.2118/206416-ms","DOIUrl":"https://doi.org/10.2118/206416-ms","url":null,"abstract":"\u0000 The article describes a method for developing low-permeability reservoirs using horizontal wells with multi-stage hydraulic fracturing. The effectiveness of the new method lies in protecting the horizontal part of the production well by drilling it through a non-reservoir plastic reservoir adjacent directly to the target reservoir. The paper considers various implementations of the technology and estimates the increase in oil recovery factor for each of them based on the results of hydrodynamic modeling. The risks associated with the implementation of the technology are considered. Methods for their reduction are proposed.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75117153","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}
Kevin Shaw, Theodore Randolph, W. Anthony, J. Harkrider, Igor Gendelman
This paper shows the importance of an integrated, multidisciplinary approach to exploiting the unconventional Domanik Play in the Volga-Urals Basin in Russia. A combination of understanding the reservoir and applying different completion techniques is necessary to verify the best way to drill, complete, and produce the basin. In 2012, DirectNeft drilled the first well specifically targeting the Domanik interval in the Volga Ural Basin. This discovery well tested oil from multiple horizons within the 350+ m (1150’) thick "Domanikoid" section. In the broad Upper Frasnian interval, Well A was the first successful hydraulic fracture treatment in the Domanik. The subsequent Well B, seven miles to the northwest, penetrated a largely identical Domanik section and was also fractured and tested in multiple horizons, including the Upper Frasnian. Well tests, logs and core analysis have identified two primary and two secondary productive intervals within the Domanik. These two wells provided the first sets of modern logs in the area, which are critical to better understand the reservoirs. In addition, the coring of key intervals and extensive analysis of those cores have proven invaluable in understanding the nature of the reservoirs. Existing well control and seismic data clearly indicate the thick section of Domanik rocks extends throughout the area. The presence and viability of oil saturated Domanik low permeability reservoirs has been confirmed by the two wells. Oil flows have been recovered from perforated intervals of the Tournaisian, Zavolzhian, Famennian and Upper Frasnian. Based on these exploration findings, subsequent operations expanded the project by drilling four horizontal wells in 2017-2018, three of which have been completed. Objectives are multi-fold and included further delineation of the four productive intervals by refining the understanding of geologic, petrophysical and geomechanical models that influence the completion and stimulation operations, ultimately impacting production. Early results from the completed wells have shown a rapid improvement in production results, showing that the multidisciplinary workflow is successful. Future tests incorporate significant increase of entry points to further prove the success of the play. This paper describes the methodology and modifications implemented based on improved understanding of the reservoir, including the use of multi-stage completion techniques. Also discussed are operational issues related to implementing state-of-the-art completion techniques including sliding sleeves, coil-tubing operations, jet cutting operations and plug and perf operations.
{"title":"Delineating the Multi-Stacked Domanik Play in the Volga-Urals Basin, Russia","authors":"Kevin Shaw, Theodore Randolph, W. Anthony, J. Harkrider, Igor Gendelman","doi":"10.2118/206407-ms","DOIUrl":"https://doi.org/10.2118/206407-ms","url":null,"abstract":"\u0000 This paper shows the importance of an integrated, multidisciplinary approach to exploiting the unconventional Domanik Play in the Volga-Urals Basin in Russia. A combination of understanding the reservoir and applying different completion techniques is necessary to verify the best way to drill, complete, and produce the basin.\u0000 In 2012, DirectNeft drilled the first well specifically targeting the Domanik interval in the Volga Ural Basin. This discovery well tested oil from multiple horizons within the 350+ m (1150’) thick \"Domanikoid\" section. In the broad Upper Frasnian interval, Well A was the first successful hydraulic fracture treatment in the Domanik. The subsequent Well B, seven miles to the northwest, penetrated a largely identical Domanik section and was also fractured and tested in multiple horizons, including the Upper Frasnian. Well tests, logs and core analysis have identified two primary and two secondary productive intervals within the Domanik.\u0000 These two wells provided the first sets of modern logs in the area, which are critical to better understand the reservoirs. In addition, the coring of key intervals and extensive analysis of those cores have proven invaluable in understanding the nature of the reservoirs. Existing well control and seismic data clearly indicate the thick section of Domanik rocks extends throughout the area. The presence and viability of oil saturated Domanik low permeability reservoirs has been confirmed by the two wells. Oil flows have been recovered from perforated intervals of the Tournaisian, Zavolzhian, Famennian and Upper Frasnian.\u0000 Based on these exploration findings, subsequent operations expanded the project by drilling four horizontal wells in 2017-2018, three of which have been completed. Objectives are multi-fold and included further delineation of the four productive intervals by refining the understanding of geologic, petrophysical and geomechanical models that influence the completion and stimulation operations, ultimately impacting production. Early results from the completed wells have shown a rapid improvement in production results, showing that the multidisciplinary workflow is successful. Future tests incorporate significant increase of entry points to further prove the success of the play.\u0000 This paper describes the methodology and modifications implemented based on improved understanding of the reservoir, including the use of multi-stage completion techniques. Also discussed are operational issues related to implementing state-of-the-art completion techniques including sliding sleeves, coil-tubing operations, jet cutting operations and plug and perf operations.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74034401","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. N. Kiselev, Il’ya Sergeevich Degtyaryov, Yurij Mikhaylovich Andronov
Synopsis. The paper describes approaches used when creating a comprehensive strategy for the development of low-permeable gas deposits of the Turonian age. Unlike to common techniques based on the experience of the previous development, the authors propose to optimize each of the constituent components of the development design, taking into account their contribution to the overall designing cycle. The efficient development strategy and technology will allow expanding the resource base of hydrocarbons at the expense of gas targets of the Turonian deposits, substantiating the efficiency of potentially promising areas of unallocated areas of the deposits.
{"title":"Setting a Development Strategy for Low-Permeable Turonian Gas Reservoirs","authors":"A. N. Kiselev, Il’ya Sergeevich Degtyaryov, Yurij Mikhaylovich Andronov","doi":"10.2118/206581-ms","DOIUrl":"https://doi.org/10.2118/206581-ms","url":null,"abstract":"\u0000 Synopsis. The paper describes approaches used when creating a comprehensive strategy for the development of low-permeable gas deposits of the Turonian age. Unlike to common techniques based on the experience of the previous development, the authors propose to optimize each of the constituent components of the development design, taking into account their contribution to the overall designing cycle. The efficient development strategy and technology will allow expanding the resource base of hydrocarbons at the expense of gas targets of the Turonian deposits, substantiating the efficiency of potentially promising areas of unallocated areas of the deposits.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76651612","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}
I. Krasnov, O. Butorin, I. Sabanchin, V. Kim, S. Zimin, A. Pshenichniy, Alexey Toporov, Igor Ivanoshchuk, R. Valeev, Artem Galimzyanov, Konstantin Naydenskiy
With the development of drilling and well completion technologies, multi-staged hydraulic fracturing (MSF) in horizontal wells has established itself as one of the most effective methods for stimulating production in fields with low permeability properties. In Eastern Siberia, this technology is at the pilot project stage. For example, at the Bolshetirskoye field, these works are being carried out to enhance the productivity of horizontal wells by increasing the connectivity of productive layers in a low- and medium- permeable porous-cavernous reservoir. However, different challenges like high permeability heterogeneity and the presence of H2S corrosive gases setting a bar higher for the requirement of the well construction design and well monitoring to achieve the maximum oil recovery factor. At the same time, well and reservoir surveillance of different parameters, which may impact on the efficiency of multi-stage hydraulic fracturing and oil contribution from each hydraulic fracture, remains a challenging and urgent task today. This article discusses the experience of using tracer technology for well monitoring with multi-stage hydraulic fracturing to obtain information on the productivity of each hydraulic fracture separately.
{"title":"The Use of Tracer Technologies for Well Monitoring with Multi-Stage Hydraulic Fracturing on Bolshetirskoye Oil Field","authors":"I. Krasnov, O. Butorin, I. Sabanchin, V. Kim, S. Zimin, A. Pshenichniy, Alexey Toporov, Igor Ivanoshchuk, R. Valeev, Artem Galimzyanov, Konstantin Naydenskiy","doi":"10.2118/206504-ms","DOIUrl":"https://doi.org/10.2118/206504-ms","url":null,"abstract":"\u0000 With the development of drilling and well completion technologies, multi-staged hydraulic fracturing (MSF) in horizontal wells has established itself as one of the most effective methods for stimulating production in fields with low permeability properties. In Eastern Siberia, this technology is at the pilot project stage. For example, at the Bolshetirskoye field, these works are being carried out to enhance the productivity of horizontal wells by increasing the connectivity of productive layers in a low- and medium- permeable porous-cavernous reservoir.\u0000 However, different challenges like high permeability heterogeneity and the presence of H2S corrosive gases setting a bar higher for the requirement of the well construction design and well monitoring to achieve the maximum oil recovery factor. At the same time, well and reservoir surveillance of different parameters, which may impact on the efficiency of multi-stage hydraulic fracturing and oil contribution from each hydraulic fracture, remains a challenging and urgent task today.\u0000 This article discusses the experience of using tracer technology for well monitoring with multi-stage hydraulic fracturing to obtain information on the productivity of each hydraulic fracture separately.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79812751","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}
Semen Idimeshev, V. Isaev, A. Tikhonov, L. Semin, D. Bannikov, Ivan Vladimirovich Velikanov, M. Ivanov, D. Kuznetsov, L. Belyakova
We present the digital slot — a tool for the development of new hydraulic fracturing technologies via digitization of slurry flow in narrow channels. We consider slurry containing fluid, proppant, and fiber components. The flow is described by a continuum mathematical model based on the lubrication theory. The numerical algorithm utilizes Lagrangian approach with finite volume pressure solver. We present the results of laboratory validation and simulation examples showing the key effects affecting solids transport in hydraulic fracturing: settling, bridging, gravity slumping, materials degradation, viscosity contrast, and bank formation.
{"title":"Digital Slot: A Tool for Optimization and Development of New Hydraulic Fracturing Technologies","authors":"Semen Idimeshev, V. Isaev, A. Tikhonov, L. Semin, D. Bannikov, Ivan Vladimirovich Velikanov, M. Ivanov, D. Kuznetsov, L. Belyakova","doi":"10.2118/206524-ms","DOIUrl":"https://doi.org/10.2118/206524-ms","url":null,"abstract":"We present the digital slot — a tool for the development of new hydraulic fracturing technologies via digitization of slurry flow in narrow channels. We consider slurry containing fluid, proppant, and fiber components. The flow is described by a continuum mathematical model based on the lubrication theory. The numerical algorithm utilizes Lagrangian approach with finite volume pressure solver. We present the results of laboratory validation and simulation examples showing the key effects affecting solids transport in hydraulic fracturing: settling, bridging, gravity slumping, materials degradation, viscosity contrast, and bank formation.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 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":"83296622","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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