A. Loginov, S. Pavlova, O. Olennikova, Andrey O. Fedorov, Irina Lomovskaya, Kira Yudina, E. Danilevich, A. Shalagina, V. Radaev
Guar-based crosslinked fluids remained the prevalent choice of frac fluid for a long period of time, since massive hydraulic fracturing was started in Russia. Traditional frac fluid contains 2535 ppt of crosslinked guar, which results in very high fluid viscosity (min 400 cp at 100 sec-1 as rule of thumb) and low retained permeability of proppant pack - around 35%. With recent move towards complex geology reservoirs in Russia, where wide propped frac is no longer an optimum solution, the need in review of current fracturing approaches emerged. In several last years local operators started to gradually move away from h igh-viscosity fluids via its partial replacement with cleaner guar-based low viscous linear gel. However, even in this case retained fracture conductivities are typically not higher than 60-70%, especially in cases when hybrid fluid systems are used - linear fluid combined with crosslinked gel. Goal to reach improved fracture conductivity opens a field for new discoveries. This study objective is to evaluate the applicability of novel clean frac fluid for conventional reservoirs in Russia. Current study is focused on development of laboratory testing procedures and testing results analysis of novel synthetic polymer-based fracturing fluid in terms of its applicability on conventional reservoirs - tight sandstones. Viscous slickwater has already been widely used on shale reservoirs in North America, however was never applied for conditions of sandstones fracturing: in mili Darcy environment, in combination with ceramic proppant, pumping via tubing, utilizing pump rates less than 10 m3/min (60 bbl/min). Fluid rheology studies, leak-off behavior, regained conductivity of the proppant pack, regained permeability of the formation, dynamic proppant transport tests and dynamic fluid viscosity evaluation are described in the paper. Elastic properties of viscous slickwater (H.Zhao, S.Danican, H.Torres, Y.Christianti, M.Nikolaev, S.Makarychev-Mikhailov, A.Bonnell, Schlumberger, 2018) provide improved dynamic proppant transport and static proppant settling, in comparison with low viscous fluid - linear guar-based gel, i.e. better horizontal and vertical proppant distribution inside the fracture. Ceramic proppant pack conductivity even with high loadings of High Viscosity Friction Reducer without breakers showed superior results - Regained conductivity reached 100%. Coreflow experiments using conventional (1-10 mD) sandstone cores demonstrated 100% regained phase permeability to hydrocarbon, proving that fluid is non-damaging to formation. As a result of numerous laboratory studies performed, Viscous slickwater was qualified as alternative fracturing fluid to conventionally used guar-based gel and has been approved for field testing campaign on conventional tight sandstones in Russia. Field trials of novel frac fluid - Viscous slickwater demonstrated positive results both in terms of pumpability and well productivity on tight sandstones 0
{"title":"Introduction of Novel Alternative to Guar-Based Fracturing Fluid for Russian Conventional Reservoirs","authors":"A. Loginov, S. Pavlova, O. Olennikova, Andrey O. Fedorov, Irina Lomovskaya, Kira Yudina, E. Danilevich, A. Shalagina, V. Radaev","doi":"10.2118/196971-ms","DOIUrl":"https://doi.org/10.2118/196971-ms","url":null,"abstract":"\u0000 Guar-based crosslinked fluids remained the prevalent choice of frac fluid for a long period of time, since massive hydraulic fracturing was started in Russia. Traditional frac fluid contains 2535 ppt of crosslinked guar, which results in very high fluid viscosity (min 400 cp at 100 sec-1 as rule of thumb) and low retained permeability of proppant pack - around 35%.\u0000 With recent move towards complex geology reservoirs in Russia, where wide propped frac is no longer an optimum solution, the need in review of current fracturing approaches emerged. In several last years local operators started to gradually move away from h igh-viscosity fluids via its partial replacement with cleaner guar-based low viscous linear gel. However, even in this case retained fracture conductivities are typically not higher than 60-70%, especially in cases when hybrid fluid systems are used - linear fluid combined with crosslinked gel. Goal to reach improved fracture conductivity opens a field for new discoveries. This study objective is to evaluate the applicability of novel clean frac fluid for conventional reservoirs in Russia.\u0000 Current study is focused on development of laboratory testing procedures and testing results analysis of novel synthetic polymer-based fracturing fluid in terms of its applicability on conventional reservoirs - tight sandstones. Viscous slickwater has already been widely used on shale reservoirs in North America, however was never applied for conditions of sandstones fracturing: in mili Darcy environment, in combination with ceramic proppant, pumping via tubing, utilizing pump rates less than 10 m3/min (60 bbl/min). Fluid rheology studies, leak-off behavior, regained conductivity of the proppant pack, regained permeability of the formation, dynamic proppant transport tests and dynamic fluid viscosity evaluation are described in the paper.\u0000 Elastic properties of viscous slickwater (H.Zhao, S.Danican, H.Torres, Y.Christianti, M.Nikolaev, S.Makarychev-Mikhailov, A.Bonnell, Schlumberger, 2018) provide improved dynamic proppant transport and static proppant settling, in comparison with low viscous fluid - linear guar-based gel, i.e. better horizontal and vertical proppant distribution inside the fracture. Ceramic proppant pack conductivity even with high loadings of High Viscosity Friction Reducer without breakers showed superior results - Regained conductivity reached 100%. Coreflow experiments using conventional (1-10 mD) sandstone cores demonstrated 100% regained phase permeability to hydrocarbon, proving that fluid is non-damaging to formation. As a result of numerous laboratory studies performed, Viscous slickwater was qualified as alternative fracturing fluid to conventionally used guar-based gel and has been approved for field testing campaign on conventional tight sandstones in Russia.\u0000 Field trials of novel frac fluid - Viscous slickwater demonstrated positive results both in terms of pumpability and well productivity on tight sandstones 0","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77391909","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, K. Schekoldin, I. Struchkov, V. Kovalenko, G. Sergeev, E. Lipatnikova
A new method for assessing the stability of the asphaltene phase in reservoir fluids using a high-pressure microscope is presented. The new method is based on the observation of the asphaltene particles sedimentation in a vertically oriented sapphire cell. This determines the size of sedimentation particles, their number and sedimentation rate. Experimental results are used as input parameters for calculating solid particles sedimentation of using the Stokes law equation. It makes possible to calculate the density and weight percent of the solid phase, evaluate the aggregative and kinetic stability of the fluid with respect to solid particles depending on thermodynamic parameters (pressure, temperature, reagent concentration). The proposed method was tested in the single-contact study of high-viscosity reservoir oil and liquid carbon dioxide and was compared with the results of asphaltene precipitation gravimetric test. According to the results analysis, were conclusions about the applicability of the new method and the mechanism of asphaltenes precipitation in high-viscosity oil when it contact with carbon dioxide. It is shown that the combination of gravimetric and visual analyzes allows to investigate the asphaltenes precipitaion separately in two processes: reduction of pressure and vaporization of fluids. This makes it possible to assess the likelihood of formation and the effectiveness of reagents for combating solid deposits in the entire process chain of oil production. Concluded that the asphaltenes precipitation in the contact of carbon dioxide and high-viscosity oil occurs according to the complex mechanism and includes intensification due to a drop in oil viscosity and damping due to mass transfer between carbon dioxide and oil phases. From this, inhibitors selection criteria are derived and the using of deasphalted oil as a stabilizer of asphaltenes is proposed.
{"title":"Investigation of Asphaltenes Precipitation Under Immiscible Interaction of Reservoir Heavy Oil and Liquid Carbon Dioxide","authors":"A. Lobanov, S. Fedorovskiy, I. Promzelev, Y. Tikhomirov, K. Schekoldin, I. Struchkov, V. Kovalenko, G. Sergeev, E. Lipatnikova","doi":"10.2118/196827-ms","DOIUrl":"https://doi.org/10.2118/196827-ms","url":null,"abstract":"\u0000 A new method for assessing the stability of the asphaltene phase in reservoir fluids using a high-pressure microscope is presented. The new method is based on the observation of the asphaltene particles sedimentation in a vertically oriented sapphire cell. This determines the size of sedimentation particles, their number and sedimentation rate. Experimental results are used as input parameters for calculating solid particles sedimentation of using the Stokes law equation. It makes possible to calculate the density and weight percent of the solid phase, evaluate the aggregative and kinetic stability of the fluid with respect to solid particles depending on thermodynamic parameters (pressure, temperature, reagent concentration). The proposed method was tested in the single-contact study of high-viscosity reservoir oil and liquid carbon dioxide and was compared with the results of asphaltene precipitation gravimetric test. According to the results analysis, were conclusions about the applicability of the new method and the mechanism of asphaltenes precipitation in high-viscosity oil when it contact with carbon dioxide. It is shown that the combination of gravimetric and visual analyzes allows to investigate the asphaltenes precipitaion separately in two processes: reduction of pressure and vaporization of fluids. This makes it possible to assess the likelihood of formation and the effectiveness of reagents for combating solid deposits in the entire process chain of oil production. Concluded that the asphaltenes precipitation in the contact of carbon dioxide and high-viscosity oil occurs according to the complex mechanism and includes intensification due to a drop in oil viscosity and damping due to mass transfer between carbon dioxide and oil phases. From this, inhibitors selection criteria are derived and the using of deasphalted oil as a stabilizer of asphaltenes is proposed.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86931780","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}
Ying Guo, Dingwei Weng, Xin Wang, Yao-yao Duan, J. Xiu, Zhuxin Chen, Jianwei Liu, M. Tang
Unconventional reservoir is characterized by its low permeability, insufficient reservoir energy and low production. To develop unconventional resource economically and efficiently, the industry has been spending tremendous resources to optimize completion, energy supplement and cluster spacing in stimulation technology by piloting – a trial approach. However, this approach tends to be time consuming and cost significant amount of money. As the fracturing modeling and stimulation technology advances, we question: "Can we use the fracturing modeling and reservoir simulation technologies to optimize well energy supplement and cluster spacing based upon Fracture Controlling Fracturing (FCF) technology, which is the latest concept for stimulation technology with successful applications in China's unconventional oil and gas development?", so that the industry can significantly save piloting time and money, and quickly find the optimal energy supplement method and cluster spacing corresponding to optimal completion. Based on the actual geological conditions of the horizontal well group of An83 block in Changqing oilfield in Ordos basin, we first built a 3-D geological and petrophysical model by Petrel and Eclipse softwares, and then calibrated the model with multi-stage fracturing production history data of each well. Local grid refinement and equivalent permeability simulation of fractures were used to optimize the crack system and cluster spacing parameters. FCF is a new generation hydraulic fracturing technology to move all the controllable reserves per well, and develop unconventional resources economically and efficiently by making fractures matching ‘sweet spots’ and ‘non-sweet spots’. The FCF emphasizes on making all the oil and gas movable by the hydraulic fracturing for the first time, the integration of reservoir pressurization, stimulation and production. It aims at moving all the oil and gas in place, developing unconventional oil and gas resources sustainable and profitable. The FCF has been successfully applied to the Ma56 block of Santang Lake in Tuha Oilfield of China. The average cluster spacing is 39.4 ft, and each stage has 5 clusters. The ‘fracture-controlled reserves’ was raised by optimizing well energy replenishment and cluster spacing based upon FCF technology. The total fluid volume injected is 151421.4bbl per well, and the formation energy is fully supplemented. Compared with neighboring wells, the oil production has increased by 1.7 times. With outstanding performance in production enhancement for unconventional oil and gas plays, FCF is worthy of extensive promotion.
{"title":"Optimization on Well Energy Supplement and Cluster Spacing Based Upon Fracture Controlling Fracturing Technology & Reservoir Simulation - An Ordos Basin Case Study","authors":"Ying Guo, Dingwei Weng, Xin Wang, Yao-yao Duan, J. Xiu, Zhuxin Chen, Jianwei Liu, M. Tang","doi":"10.2118/196981-ms","DOIUrl":"https://doi.org/10.2118/196981-ms","url":null,"abstract":"\u0000 Unconventional reservoir is characterized by its low permeability, insufficient reservoir energy and low production. To develop unconventional resource economically and efficiently, the industry has been spending tremendous resources to optimize completion, energy supplement and cluster spacing in stimulation technology by piloting – a trial approach. However, this approach tends to be time consuming and cost significant amount of money. As the fracturing modeling and stimulation technology advances, we question: \"Can we use the fracturing modeling and reservoir simulation technologies to optimize well energy supplement and cluster spacing based upon Fracture Controlling Fracturing (FCF) technology, which is the latest concept for stimulation technology with successful applications in China's unconventional oil and gas development?\", so that the industry can significantly save piloting time and money, and quickly find the optimal energy supplement method and cluster spacing corresponding to optimal completion.\u0000 Based on the actual geological conditions of the horizontal well group of An83 block in Changqing oilfield in Ordos basin, we first built a 3-D geological and petrophysical model by Petrel and Eclipse softwares, and then calibrated the model with multi-stage fracturing production history data of each well. Local grid refinement and equivalent permeability simulation of fractures were used to optimize the crack system and cluster spacing parameters. FCF is a new generation hydraulic fracturing technology to move all the controllable reserves per well, and develop unconventional resources economically and efficiently by making fractures matching ‘sweet spots’ and ‘non-sweet spots’. The FCF emphasizes on making all the oil and gas movable by the hydraulic fracturing for the first time, the integration of reservoir pressurization, stimulation and production. It aims at moving all the oil and gas in place, developing unconventional oil and gas resources sustainable and profitable.\u0000 The FCF has been successfully applied to the Ma56 block of Santang Lake in Tuha Oilfield of China. The average cluster spacing is 39.4 ft, and each stage has 5 clusters. The ‘fracture-controlled reserves’ was raised by optimizing well energy replenishment and cluster spacing based upon FCF technology. The total fluid volume injected is 151421.4bbl per well, and the formation energy is fully supplemented. Compared with neighboring wells, the oil production has increased by 1.7 times. With outstanding performance in production enhancement for unconventional oil and gas plays, FCF is worthy of extensive promotion.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80415360","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}
Bulat Magizov, T. Topalova, O. Loznyuk, Evgeniy Simon, A. Orlov, V. Krupeev, Dmitry Shakhov
The task of choosing the sidetrack trajectory for drilling is one of the most common among specialists while workovers planning in oil and especially in gas fields. This task is solved by reservoir engineers, geologists and drilling engineers, both in a team and separately. Despite the widespread use of software for processing and analyzing the data and high automation of most routine tasks, many oil and gas companies lack a unified methodology for choosing sidetrack trajectory. Each oil and gas company has its own approach to this task. Usually, the process of analyzing candidates is based on the expert opinion of the well design engineer and has several limitations, such as: ▪Short deadlines - on average, it takes from two to three weeks to select the sidetrack drilling trajectory.▪Low automation of the process of creating and analyzing the trajectory - the trajectory is created by a specialist manually, this process takes, considering the time for analysis, from two to four days for one trajectory. As a result, about five candidates are considered for the allotted time.▪Analysis of a small number of influencing factors — two-dimensional maps of averaged permeability, residual reserves maps, a seismic map of average amplitudes, as well as the proximity of the candidate to the existing well stock are mainly considered during analysis of the trajectory.▪Prediction of the flow rates is not always based on the hydrodynamic model - when calculating the candidate's starting flow rate due to tight deadlines, not all trajectories are analyzed using the hydrodynamic model, for part of the trajectories flow rates are calculated only using analytical techniques, such as the Joshi equation (Joshi, 2018).▪The risk of human factor. Sidetrack drilling, like other workovers, is aimed at increasing the flow rate of the well and the cumulative production of the entire field. In gas fields with falling production and high drilling density, sidetrack drilling can help significantly extend production time with the same level or increase production. Drilling a sidetrack, rather than a new well, can significantly reduce drilling costs, since the main well has already been drilled. Potentially, almost any well, especially with falling production rate or high water cut, can be a candidate for sidetrack drilling. According to the data from the Federal Supervision of Natural Resources in 2017, almost a quarter of all wells in Russia are inactive or shut, which is almost 60,000 wells.
{"title":"Automated Identification of the Optimal Sidetrack Location by Multivariant Analysis and Numerical Modeling. A Real Case Study on a Gas Field","authors":"Bulat Magizov, T. Topalova, O. Loznyuk, Evgeniy Simon, A. Orlov, V. Krupeev, Dmitry Shakhov","doi":"10.2118/196922-ms","DOIUrl":"https://doi.org/10.2118/196922-ms","url":null,"abstract":"\u0000 The task of choosing the sidetrack trajectory for drilling is one of the most common among specialists while workovers planning in oil and especially in gas fields. This task is solved by reservoir engineers, geologists and drilling engineers, both in a team and separately. Despite the widespread use of software for processing and analyzing the data and high automation of most routine tasks, many oil and gas companies lack a unified methodology for choosing sidetrack trajectory. Each oil and gas company has its own approach to this task. Usually, the process of analyzing candidates is based on the expert opinion of the well design engineer and has several limitations, such as: ▪Short deadlines - on average, it takes from two to three weeks to select the sidetrack drilling trajectory.▪Low automation of the process of creating and analyzing the trajectory - the trajectory is created by a specialist manually, this process takes, considering the time for analysis, from two to four days for one trajectory. As a result, about five candidates are considered for the allotted time.▪Analysis of a small number of influencing factors — two-dimensional maps of averaged permeability, residual reserves maps, a seismic map of average amplitudes, as well as the proximity of the candidate to the existing well stock are mainly considered during analysis of the trajectory.▪Prediction of the flow rates is not always based on the hydrodynamic model - when calculating the candidate's starting flow rate due to tight deadlines, not all trajectories are analyzed using the hydrodynamic model, for part of the trajectories flow rates are calculated only using analytical techniques, such as the Joshi equation (Joshi, 2018).▪The risk of human factor.\u0000 Sidetrack drilling, like other workovers, is aimed at increasing the flow rate of the well and the cumulative production of the entire field. In gas fields with falling production and high drilling density, sidetrack drilling can help significantly extend production time with the same level or increase production. Drilling a sidetrack, rather than a new well, can significantly reduce drilling costs, since the main well has already been drilled. Potentially, almost any well, especially with falling production rate or high water cut, can be a candidate for sidetrack drilling. According to the data from the Federal Supervision of Natural Resources in 2017, almost a quarter of all wells in Russia are inactive or shut, which is almost 60,000 wells.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82594087","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}
V. Lompik, N. Dadakin, M. Nukhaev, K. Rymarenko, Artem Makatrov, Ildus Zaynullin, D. Bikmeev
Before implementing any chemical enhanced oil recovery project at the field, it is very important to carry out a feasibility study, which is impossible without determining their effectiveness under laboratory conditions. The task of laboratory research is to determine all the parameters of surfactant and polymer solutions, necessary for further analytical evaluation and reservoir simulation. It is necessary to conduct laboratory experiments to perform technical and economic assessment of the chemical EORs implementation. One of the most important issues here is to determine the amount of reagent held in the pore space of the reservoir. The retention parameter determines how much reagent needs to be injected to achieve the required displacement efficiency. It directly affects reagent consumption and economic efficiency. This paper discusses various methods for determining the amount of reagent retained in the reservoir; it can be surfactant species or a polymer. To solve the problem of reducing the time for the experimental part, an algorithm of an experiment was developed, which makes it possible to determine the retention parameters in a shorter time and with less labor. This method was tested and showed its effectiveness in the course of a technical and economic study on the possibility of implementing polymer flooding for a field in Eastern Siberia. As a result of the experiments, the relationships between the surfactant or polymer retention and their concentration, and also between permeability and the amount of reagent adsorbed were found. The effect of salinity on the retention parameter was determined, the fact of desorption for both surfactants and polymers was revealed. Inaccessible pore volume for polymer was determined.
{"title":"Step-Up Concentration Method for Chemical Agents’ Adsorption Measurement in Porous Media","authors":"V. Lompik, N. Dadakin, M. Nukhaev, K. Rymarenko, Artem Makatrov, Ildus Zaynullin, D. Bikmeev","doi":"10.2118/196771-ms","DOIUrl":"https://doi.org/10.2118/196771-ms","url":null,"abstract":"\u0000 Before implementing any chemical enhanced oil recovery project at the field, it is very important to carry out a feasibility study, which is impossible without determining their effectiveness under laboratory conditions.\u0000 The task of laboratory research is to determine all the parameters of surfactant and polymer solutions, necessary for further analytical evaluation and reservoir simulation. It is necessary to conduct laboratory experiments to perform technical and economic assessment of the chemical EORs implementation. One of the most important issues here is to determine the amount of reagent held in the pore space of the reservoir.\u0000 The retention parameter determines how much reagent needs to be injected to achieve the required displacement efficiency. It directly affects reagent consumption and economic efficiency.\u0000 This paper discusses various methods for determining the amount of reagent retained in the reservoir; it can be surfactant species or a polymer. To solve the problem of reducing the time for the experimental part, an algorithm of an experiment was developed, which makes it possible to determine the retention parameters in a shorter time and with less labor. This method was tested and showed its effectiveness in the course of a technical and economic study on the possibility of implementing polymer flooding for a field in Eastern Siberia.\u0000 As a result of the experiments, the relationships between the surfactant or polymer retention and their concentration, and also between permeability and the amount of reagent adsorbed were found. The effect of salinity on the retention parameter was determined, the fact of desorption for both surfactants and polymers was revealed. Inaccessible pore volume for polymer was determined.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89533333","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. Kornilov, A. Zhirov, A. Petrakov, T. Rogova, Y. Kurelenkova, I. Afanasiev, G. Sansiev, G. Fedorchenko, G. Fursov, M. Kubrak, T. Altmann, Nicole Lichterfeld-Weber, C. Bittner, G. Oetter, E. Helwig
The paper includes the scheme of surfactant composition selection and the approach to evaluate potential results of injection for Central-Khoreiver Uplift (CKU) fields with carbonate reservoirs. Several scenarios of surfactant composition injection were studied, using high salinity treated formation water (up to 210 g/l) without applying salinity gradient. The first step of surfactant composition selection included testing of water solution stability in formation water that is characteristic for CKU conditions. Then interfacial tension of surfactant water solution with oil was measured, as well as adsorption properties. The target values of interfacial tension were set in the range around 10-2, and not higher than 10-1 mN/m. Filtration experiments on composite core model were conducted to evaluate the efficnency of selected composition. Development and tuning of linear model for the filtration experiment matched the laboratory results. Obtained parameters are included into the sector model of field development unit, considering the conversion of one of the wells to injection of chemicals. The paper presents preliminary evaluation of technological efficiency for the selected scheme of composition injection. The approach presented in the current paper can be used to plan injection of surfactant-based compositions into carbonate formation with properties that are similar to investigated values. Applying surfactants that are compatible with high salinity formation water makes possible to use treated produced water as injection medium and it decreases the costs of mix water preparation.
{"title":"Selection of Effective Surfactant Composition to Improve Oil Displacement Efficiency in Carbonate Reservoirs with High Salinity Formation Water","authors":"A. Kornilov, A. Zhirov, A. Petrakov, T. Rogova, Y. Kurelenkova, I. Afanasiev, G. Sansiev, G. Fedorchenko, G. Fursov, M. Kubrak, T. Altmann, Nicole Lichterfeld-Weber, C. Bittner, G. Oetter, E. Helwig","doi":"10.2118/196772-ms","DOIUrl":"https://doi.org/10.2118/196772-ms","url":null,"abstract":"\u0000 The paper includes the scheme of surfactant composition selection and the approach to evaluate potential results of injection for Central-Khoreiver Uplift (CKU) fields with carbonate reservoirs. Several scenarios of surfactant composition injection were studied, using high salinity treated formation water (up to 210 g/l) without applying salinity gradient. The first step of surfactant composition selection included testing of water solution stability in formation water that is characteristic for CKU conditions. Then interfacial tension of surfactant water solution with oil was measured, as well as adsorption properties. The target values of interfacial tension were set in the range around 10-2, and not higher than 10-1 mN/m.\u0000 Filtration experiments on composite core model were conducted to evaluate the efficnency of selected composition. Development and tuning of linear model for the filtration experiment matched the laboratory results. Obtained parameters are included into the sector model of field development unit, considering the conversion of one of the wells to injection of chemicals. The paper presents preliminary evaluation of technological efficiency for the selected scheme of composition injection.\u0000 The approach presented in the current paper can be used to plan injection of surfactant-based compositions into carbonate formation with properties that are similar to investigated values. Applying surfactants that are compatible with high salinity formation water makes possible to use treated produced water as injection medium and it decreases the costs of mix water preparation.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77244208","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}
Mikhail Baklushin, N. Velikaya, V. Zyryanov, D. Vologdin
Production sections of Western Siberian wells consist of gas, oil, and water-saturated sandstones; therefore, it is extremely important to help ensure zonal isolation to help prevent fluid migration from the overlaid water and gas formations into the oil-producing zones. Isolating the water and gas zones with conventional cement has not been a complete success because fluid migration was experienced through a channel or damage to the cement sheath. A typical solution sets an annular packer in the production casing zone beneath the gas and water-bearing sandstones as backup if the cement fails to provide a full annular barrier. Using the annular packer has some limitations, and potential risks of early activation or nonactivation of the annular packer often contributes to nonproductive time (NPT). An alternative solution used in Western Siberia combines resin-polymer and cement, which provides a cement sheath with improved mechanical properties, such as reduced permeability, increased ductility, and improved shear bond to casing. The successful use of a resin-polymer cement blend as an alternative to using an annular packer, advantages of using this system, and recommendations for implementing this technology are discussed.
{"title":"Applying a Resin-Cement System to Help Prevent Fluid Migration in the Annulus: Case Study, Western Siberia","authors":"Mikhail Baklushin, N. Velikaya, V. Zyryanov, D. Vologdin","doi":"10.2118/196799-ms","DOIUrl":"https://doi.org/10.2118/196799-ms","url":null,"abstract":"\u0000 Production sections of Western Siberian wells consist of gas, oil, and water-saturated sandstones; therefore, it is extremely important to help ensure zonal isolation to help prevent fluid migration from the overlaid water and gas formations into the oil-producing zones. Isolating the water and gas zones with conventional cement has not been a complete success because fluid migration was experienced through a channel or damage to the cement sheath. A typical solution sets an annular packer in the production casing zone beneath the gas and water-bearing sandstones as backup if the cement fails to provide a full annular barrier.\u0000 Using the annular packer has some limitations, and potential risks of early activation or nonactivation of the annular packer often contributes to nonproductive time (NPT). An alternative solution used in Western Siberia combines resin-polymer and cement, which provides a cement sheath with improved mechanical properties, such as reduced permeability, increased ductility, and improved shear bond to casing. The successful use of a resin-polymer cement blend as an alternative to using an annular packer, advantages of using this system, and recommendations for implementing this technology are discussed.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87418608","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, there is only one realizable technology for development of gas shale and tight gas formations which is based on the applying of the horizontal well systems with multi-stage hydraulic fracturing. The efficiency of shale and tight gas production using this technology in a complex manner depends on some parameters of the wells design, among which, first of all, it is necessary to note: wellbore length, half-length of hydraulic fracture and number of hydraulic fracturing stages. Gas production indicators from shale and tigth formations also significantly depend on the wells grid density. In this paper, we studied the influence of these factors on the shale gas and tight gas production from reservoirs with different permeability. Also, we present the approach to determine the optimal values of wells parameters and the wells grid density
{"title":"Optimization of Unconventional Gas Reservoirs Development by Horizontal Wells with Multiple Hydraulic Fracturing","authors":"A. Shandrygin","doi":"10.2118/196741-ms","DOIUrl":"https://doi.org/10.2118/196741-ms","url":null,"abstract":"\u0000 Currently, there is only one realizable technology for development of gas shale and tight gas formations which is based on the applying of the horizontal well systems with multi-stage hydraulic fracturing. The efficiency of shale and tight gas production using this technology in a complex manner depends on some parameters of the wells design, among which, first of all, it is necessary to note: wellbore length, half-length of hydraulic fracture and number of hydraulic fracturing stages. Gas production indicators from shale and tigth formations also significantly depend on the wells grid density. In this paper, we studied the influence of these factors on the shale gas and tight gas production from reservoirs with different permeability. Also, we present the approach to determine the optimal values of wells parameters and the wells grid density","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91103507","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}
Muratbek Aibazarov, B. Kaliyev, G. Mutaliyev, Emanuele Vignati, D. Gulyaev, V. Krichevsky, A. Buyanov
Well spacing optimization is very important at the stage of drilling the reservoir. It is critical for the whole project economics. After the reservoir is already drilled it is very important to understand does existing wells drain all the reserves of infill drilling requires to improve recovery. Such task was solved on a tested area - Western part of Karachaganak gas condensate field. It has a complex geology, built as a massive heterogeneous carbonate reef of a Carboniferous age. PVT properties of the reservoir fluid significantly varies with depth. The area is produced with horizontal wells to maximize contact with the reservoir. The Multi-well Retrospective Testing (MRT) on base of multi-well deconvolution of historical rate and bottom-hole revealed well drainage area and well interference (1 – Aslanyan, 2018; 2 – Aslanyan 2017, 3 – Aslanyan 2019). The MRT study is showing a strong pressure depletion trend and a fair connection between wells in the certain areas like core of western build up.
{"title":"Well Spacing Verification At Gas Condensate Field Using Deconvolution Driven Long-Term Pressure and Rate Analysis","authors":"Muratbek Aibazarov, B. Kaliyev, G. Mutaliyev, Emanuele Vignati, D. Gulyaev, V. Krichevsky, A. Buyanov","doi":"10.2118/196925-ms","DOIUrl":"https://doi.org/10.2118/196925-ms","url":null,"abstract":"\u0000 Well spacing optimization is very important at the stage of drilling the reservoir. It is critical for the whole project economics. After the reservoir is already drilled it is very important to understand does existing wells drain all the reserves of infill drilling requires to improve recovery. Such task was solved on a tested area - Western part of Karachaganak gas condensate field. It has a complex geology, built as a massive heterogeneous carbonate reef of a Carboniferous age. PVT properties of the reservoir fluid significantly varies with depth. The area is produced with horizontal wells to maximize contact with the reservoir.\u0000 The Multi-well Retrospective Testing (MRT) on base of multi-well deconvolution of historical rate and bottom-hole revealed well drainage area and well interference (1 – Aslanyan, 2018; 2 – Aslanyan 2017, 3 – Aslanyan 2019). The MRT study is showing a strong pressure depletion trend and a fair connection between wells in the certain areas like core of western build up.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91419186","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. Guryanov, R. Gazizov, E. Medvedev, K. Ovchinnikov, P. Buzin, A. Katashov
The primary objective of the technical development and underlying principles described in this article is the creation of physicochemical principles, of which the practical implementation allows users to quickly and accurately conduct production logging of horizontal wells after conducting multi-stage hydraulic fracturing. The main physical phenomenon applied in the described method is the fluorescence of polymer microspheres – marker-reporters ranging in size from several hundred nanometers to several microns and containing quantum dots. Marker-reporters pass from synthesis and injection of proppant/sand into the polymer shell at our company's production facilities to high-precision instrumental determination of their concentration in formation fluid samples using flow cytofluorometry method in the laboratory. This method includes the following stages: Synthesis of marker-reporters containing quantum dots Preparation of polymer-coated proppant / sand with markers Injection of the marked polymer-coated proppant / sand into the well during MFrac, followed by formation fluid filtration through it Formation fluid sampling Sample preparation for obtaining samples to be analyzed with the flow cytometer Determination of marker-reporter concentrations in the samples by flow cytofluorometry data processing, also with our corporate software based on machine- learning principles All the stages mentioned above are constantly being improved and optimized. The description of each stage of the relevant technological process is described below with a "historical reference" to the technological development behind it. The characteristics of the marked polymer-coated proppant Geosplit are also provided herein.
{"title":"Application of Fluorescent Markers to Determine the Formation Fluid Inflow After MFrac","authors":"A. Guryanov, R. Gazizov, E. Medvedev, K. Ovchinnikov, P. Buzin, A. Katashov","doi":"10.2118/196776-ms","DOIUrl":"https://doi.org/10.2118/196776-ms","url":null,"abstract":"\u0000 The primary objective of the technical development and underlying principles described in this article is the creation of physicochemical principles, of which the practical implementation allows users to quickly and accurately conduct production logging of horizontal wells after conducting multi-stage hydraulic fracturing.\u0000 The main physical phenomenon applied in the described method is the fluorescence of polymer microspheres – marker-reporters ranging in size from several hundred nanometers to several microns and containing quantum dots. Marker-reporters pass from synthesis and injection of proppant/sand into the polymer shell at our company's production facilities to high-precision instrumental determination of their concentration in formation fluid samples using flow cytofluorometry method in the laboratory. This method includes the following stages:\u0000 Synthesis of marker-reporters containing quantum dots Preparation of polymer-coated proppant / sand with markers Injection of the marked polymer-coated proppant / sand into the well during MFrac, followed by formation fluid filtration through it Formation fluid sampling Sample preparation for obtaining samples to be analyzed with the flow cytometer Determination of marker-reporter concentrations in the samples by flow cytofluorometry data processing, also with our corporate software based on machine- learning principles\u0000 All the stages mentioned above are constantly being improved and optimized. The description of each stage of the relevant technological process is described below with a \"historical reference\" to the technological development behind it. The characteristics of the marked polymer-coated proppant Geosplit are also provided herein.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83417964","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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