A comparison of the criteria for the shear strength (linear and nonlinear) with different stress-strain state and variations of the parameters of fractures. Often, the first criterion is applied in petroleum engineering because of its "availability" in the parameters used, which do not require laborious calculations. But when calculating quantitative properties of fractures such as permeability and aperture, knowledge of the second criterion is required. This paper demonstrates the results of finite elemental modeling of a fractured reservoir (3D) under plastic deformation conditions with an estimate of mechanical and conductive aperture, as well as permeability.
{"title":"Evaluation of Conductive Fracture Aperture Based on a Detailed Geomechanical Model: Myth or Reality in the Context of Complex Fractured Reservoir?","authors":"S. Zhigulskiy, S. Lukin","doi":"10.2118/196896-ms","DOIUrl":"https://doi.org/10.2118/196896-ms","url":null,"abstract":"\u0000 A comparison of the criteria for the shear strength (linear and nonlinear) with different stress-strain state and variations of the parameters of fractures. Often, the first criterion is applied in petroleum engineering because of its \"availability\" in the parameters used, which do not require laborious calculations. But when calculating quantitative properties of fractures such as permeability and aperture, knowledge of the second criterion is required. This paper demonstrates the results of finite elemental modeling of a fractured reservoir (3D) under plastic deformation conditions with an estimate of mechanical and conductive aperture, as well as permeability.","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":"85391438","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. Fomenkov, Ilya Pinigin, Maxim Mikliayev, A. Fedyanin
Drilling operations within the Volga-Urals oil and gas province have a history of drilling problems manifested in partial and total losses of drilling fluid. As a result of these challenges, the companies developing and operating oil and gas fields within the region encounter the following: Significant nonproductive time (NPT) losses and additional financial costs (Urdaneta et al. 2015)Low-quality casing cementing operations proven by sonic cement-bond logging (CBL)Costly remedial cementing and sidetracking or redrilling operations because drilling ahead is no longer possibleWell abandonment, etc. Large-size particle-bridging materials are not efficient for blocking thief zones with wide fracture openings or vast cavernous intervals because they exceed the size of bridging material (Canson 1985). Technologies based on a different principle are necessary to enable efficient plugging within fractures of such thief zones (e.g., special-purpose cement-slurry-based fluid systems with distinctive thixotropic properties developing high gel strength in a short time to assist in controlling and to help reduce drilling fluid losses of any magnitude). During 2016, in cooperation with the operating company, a decision was made to conduct pilot field trials of a new method. The new special-purpose thixotropic cement slurry used within the Volga-Urals oil and gas province is a fluid characterized by low content of solid abrasive particles and by unique rheology. This slurry becomes fluid as soon as shear is applied to it and remains fluid while in dynamic state, such as when pumping downhole or circulating in an averaging tank. While shearing force is reduced, slurry viscosity increases. This fluid forms an internal gel structure after a short static period followed by intensive gelling and gel strength (shear force) development. The slurry can be squeezed into the thief zone through the bottomhole assembly (BHA), saving tripping time (Urdaneta 2016). Plug slurry density can be adjusted from 1.2 to 1.8 g/cm3 for service temperature within the 38 to 110°C range, perfectly matching virtually all downhole conditions within the region (Duffy et al. 2017). This thixotropic cement slurry formula has a simple composition and dissolves well in water using a dedicated averaging tank provided with a circulating mixing system. Owing to distinctive thixotropic properties of the slurry, its performance at downhole conditions (temperature and pressure) is verified using laboratory high-pressure/high-temperature (HP/HT) consistometer testing (on-off-on mode). The on-off-on test helps clearly define how thixotropic properties of the lightweight thixotropic slurry manifest during the operation. Signature features of this test are distinct spikes in slurry consistency (Bc) recorded on the thickening diagram after a short static period. At the same time, this thixotropic cement slurry is easily reversed to a fluid state by resuming circulation or by applying some shearing f
{"title":"Using Thixotropic Cement Slurry for Lost Circulation Control: Case History, Volga-Urals Region","authors":"A. Fomenkov, Ilya Pinigin, Maxim Mikliayev, A. Fedyanin","doi":"10.2118/196813-ms","DOIUrl":"https://doi.org/10.2118/196813-ms","url":null,"abstract":"\u0000 Drilling operations within the Volga-Urals oil and gas province have a history of drilling problems manifested in partial and total losses of drilling fluid. As a result of these challenges, the companies developing and operating oil and gas fields within the region encounter the following: Significant nonproductive time (NPT) losses and additional financial costs (Urdaneta et al. 2015)Low-quality casing cementing operations proven by sonic cement-bond logging (CBL)Costly remedial cementing and sidetracking or redrilling operations because drilling ahead is no longer possibleWell abandonment, etc.\u0000 Large-size particle-bridging materials are not efficient for blocking thief zones with wide fracture openings or vast cavernous intervals because they exceed the size of bridging material (Canson 1985). Technologies based on a different principle are necessary to enable efficient plugging within fractures of such thief zones (e.g., special-purpose cement-slurry-based fluid systems with distinctive thixotropic properties developing high gel strength in a short time to assist in controlling and to help reduce drilling fluid losses of any magnitude).\u0000 During 2016, in cooperation with the operating company, a decision was made to conduct pilot field trials of a new method. The new special-purpose thixotropic cement slurry used within the Volga-Urals oil and gas province is a fluid characterized by low content of solid abrasive particles and by unique rheology. This slurry becomes fluid as soon as shear is applied to it and remains fluid while in dynamic state, such as when pumping downhole or circulating in an averaging tank. While shearing force is reduced, slurry viscosity increases.\u0000 This fluid forms an internal gel structure after a short static period followed by intensive gelling and gel strength (shear force) development. The slurry can be squeezed into the thief zone through the bottomhole assembly (BHA), saving tripping time (Urdaneta 2016). Plug slurry density can be adjusted from 1.2 to 1.8 g/cm3 for service temperature within the 38 to 110°C range, perfectly matching virtually all downhole conditions within the region (Duffy et al. 2017). This thixotropic cement slurry formula has a simple composition and dissolves well in water using a dedicated averaging tank provided with a circulating mixing system. Owing to distinctive thixotropic properties of the slurry, its performance at downhole conditions (temperature and pressure) is verified using laboratory high-pressure/high-temperature (HP/HT) consistometer testing (on-off-on mode). The on-off-on test helps clearly define how thixotropic properties of the lightweight thixotropic slurry manifest during the operation. Signature features of this test are distinct spikes in slurry consistency (Bc) recorded on the thickening diagram after a short static period. At the same time, this thixotropic cement slurry is easily reversed to a fluid state by resuming circulation or by applying some shearing f","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":"78214202","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}
Artem Basov, O. Bukov, D. Lazutkin, A. Olyunin, V. Kuznetsov, A. Ipatov, T. Shevchuk, K. Saprykina, K. Ovchinnikov, Igor Novikov
There has been an increased interest in horizontal wells production logging using markers due to objective difficulties not only in conducting geophysical production logging and data interpretation, but also because existing technologies provide bottom hole data only for a very short time period when the PLT complex is in the well. Marker technologies enable users to obtain data in a much larger volume and practically non-stop for several years without changing the well mode of operation. This in turn allows for analyzing the influence of many external factors on the horizontal well intervals operation. This article presents the experience of marker technologies that were tested and implemented at Gazpromneft PJSC sites from 2016 to 2019, and is aimed at the systematization of objectives and requirements for the technology, as well as addressing important issues during the tendering procedures for the oil producing companies.
{"title":"Evolution of Horizontal Wells Production Logging Using Markers","authors":"Artem Basov, O. Bukov, D. Lazutkin, A. Olyunin, V. Kuznetsov, A. Ipatov, T. Shevchuk, K. Saprykina, K. Ovchinnikov, Igor Novikov","doi":"10.2118/196830-ms","DOIUrl":"https://doi.org/10.2118/196830-ms","url":null,"abstract":"\u0000 There has been an increased interest in horizontal wells production logging using markers due to objective difficulties not only in conducting geophysical production logging and data interpretation, but also because existing technologies provide bottom hole data only for a very short time period when the PLT complex is in the well. Marker technologies enable users to obtain data in a much larger volume and practically non-stop for several years without changing the well mode of operation. This in turn allows for analyzing the influence of many external factors on the horizontal well intervals operation.\u0000 This article presents the experience of marker technologies that were tested and implemented at Gazpromneft PJSC sites from 2016 to 2019, and is aimed at the systematization of objectives and requirements for the technology, as well as addressing important issues during the tendering procedures for the oil producing companies.","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":"73105881","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. Galimkhanov, D. Okhotnikov, L. Ginzburg, A. Bakhtin, Yuliy Sidorov, P. Kuzmin, S. Kulikov, Gurban Veliyev, Maytham Badrawi
This paper presents a study, illustrating results of effective cooperation between the Operator Company of the Kuyumbinskoye field, Drilling Contractor, and Service Company involved in the construction of the horizontal well using the technology of Managed Pressure Drilling (MPD). This article also describes the challenges encountered and successfully implemented engineering solutions permitting to meet these challenges. The main challenge in the Kuyumbinskoye field is the high risk of mud losses in the productive interval. The complex geological conditions as well as the anisotropy of the productive horizon complicate the prediction of catastrophic mud losses zones location. Approximately 50% of the wells were not drilled to the planned depths. To solve this problem, in 2017 a pilot project using MPD technology was initiated. The main goals to be reached by the implementation of this technology were drilling efficiency improvement, risk management, and well construction cost efficiency improvement. In order to achieve the goals, equipment was selected, a comprehensive well construction program was developed and detailed work plans were prepared. As a result of thorough planning and close cooperation at all work stages; the multidisciplinary team successfully completed the construction of 11 wells with an average extension of a horizontal interval of approximately 1000 m, drastically reducing fluid losses and associated non-productive time (NPT). By eliminating NPT and thus increasing the effective rate of penetration (ROP) during one of the wells, the drilling time of the lateral section was reduced to seven days, comparing to an average drilling time of the horizontal section of approximately 20-25 days (with conventional drilling). In addition, the average losses of drilling fluid per well were decreased by more than 1000 m3. The application of specially developed technological solutions during this pilot project not only ensured the attainment of target depths and geological objectives but also confirmed the potential of producing crude oil while drilling. Thus, allow to replenish encountered losses "on the fly" and to save time otherwise required to spend on the drilling fluid preparation. In addition to a technological breakthrough, it is important to emphasize that a high level of Health, Safety, Quality, and Environmental protection (HSQE) was achieved, and no major incidents or accidents were recorded during the entire project. Based on the lessons learned, several engineering, organizational and strategical resolutions were made to further streamline and optimize the well construction process in the field.
{"title":"Successful Implementation of Managed Pressure Drilling Technology Under the Conditions of Catastrophic Mud Losses in the Kuyumbinskoe Field","authors":"A. Galimkhanov, D. Okhotnikov, L. Ginzburg, A. Bakhtin, Yuliy Sidorov, P. Kuzmin, S. Kulikov, Gurban Veliyev, Maytham Badrawi","doi":"10.2118/196791-ms","DOIUrl":"https://doi.org/10.2118/196791-ms","url":null,"abstract":"\u0000 This paper presents a study, illustrating results of effective cooperation between the Operator Company of the Kuyumbinskoye field, Drilling Contractor, and Service Company involved in the construction of the horizontal well using the technology of Managed Pressure Drilling (MPD). This article also describes the challenges encountered and successfully implemented engineering solutions permitting to meet these challenges.\u0000 The main challenge in the Kuyumbinskoye field is the high risk of mud losses in the productive interval. The complex geological conditions as well as the anisotropy of the productive horizon complicate the prediction of catastrophic mud losses zones location. Approximately 50% of the wells were not drilled to the planned depths.\u0000 To solve this problem, in 2017 a pilot project using MPD technology was initiated. The main goals to be reached by the implementation of this technology were drilling efficiency improvement, risk management, and well construction cost efficiency improvement. In order to achieve the goals, equipment was selected, a comprehensive well construction program was developed and detailed work plans were prepared.\u0000 As a result of thorough planning and close cooperation at all work stages; the multidisciplinary team successfully completed the construction of 11 wells with an average extension of a horizontal interval of approximately 1000 m, drastically reducing fluid losses and associated non-productive time (NPT). By eliminating NPT and thus increasing the effective rate of penetration (ROP) during one of the wells, the drilling time of the lateral section was reduced to seven days, comparing to an average drilling time of the horizontal section of approximately 20-25 days (with conventional drilling). In addition, the average losses of drilling fluid per well were decreased by more than 1000 m3. The application of specially developed technological solutions during this pilot project not only ensured the attainment of target depths and geological objectives but also confirmed the potential of producing crude oil while drilling. Thus, allow to replenish encountered losses \"on the fly\" and to save time otherwise required to spend on the drilling fluid preparation.\u0000 In addition to a technological breakthrough, it is important to emphasize that a high level of Health, Safety, Quality, and Environmental protection (HSQE) was achieved, and no major incidents or accidents were recorded during the entire project. Based on the lessons learned, several engineering, organizational and strategical resolutions were made to further streamline and optimize the well construction process in the field.","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":"73192696","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}
K. Chettykbayeva, Margarita Ibragimova, Andrey B. Osipov, Y. Petrakov, Alexey Sobolev, O. Tatur
This article is the first part of the geomechanical calculations performed in order to optimize the drilling and production operations of the first horizontal wells with target formation M in the Boca de Jaruco field, Republic of Cuba. Here, the analyzed data included regional geology, tectonics and stratigraphy, different types of well logging, the pressure curves while steam operations, core samples and drilling history. The outcome of this part of the work is the assessment of the current stress regime, stress directions and the stability windows for the planned wells. Moreover, the program of additional studies and logs acquisition was elaborated, as at this stage there is not enough data to confidently quantify the stress state, the core samples are not yet tested for rock's deformation and strength properties, and it is hardly possible to find carbonate bitumen deposits under development anywhere in the world which are analogous to the Boca de Jaruco field (with the sole exception of Grosmont in Northern Alberta, Canada). After the wells are drilled (presumably by the end of 2019) and the required information is collected (such as mechanical core testing under elevated temperatures, image logs in the deviated boreholes, etc.), the second part of the work is to be performed, which would include the analysis of the drilling results and the assessment of the cap rock behavior, pore pressure and porosity-permeability changes due to steam injection.
本文是为了优化古巴Boca de Jaruco油田目标地层M的第一口水平井的钻井和生产作业而进行的地质力学计算的第一部分。分析的数据包括区域地质、构造、地层、不同类型的测井、蒸汽作业时的压力曲线、岩心样品和钻井历史。这部分工作的结果是评估当前应力状态、应力方向和计划井的稳定性窗口。此外，由于现阶段没有足够的数据来确定应力状态，岩心样品尚未测试岩石的变形和强度特性，并且几乎不可能在世界上任何地方找到与Boca de Jaruco油田类似的碳酸盐岩沥青矿床(加拿大阿尔伯塔省北部的Grosmont除外)，因此详细说明了额外研究和测井采集计划。在钻井完成(预计在2019年底)并收集所需信息(例如高温下的机械岩心测试，斜井中的图像测井等)后，将进行第二部分工作，其中包括对钻井结果的分析以及盖层行为，孔隙压力和孔隙度-渗透率变化的评估。
{"title":"Geomechanical Considerations when Planning SAGD Wells, a Case Study from Cuba","authors":"K. Chettykbayeva, Margarita Ibragimova, Andrey B. Osipov, Y. Petrakov, Alexey Sobolev, O. Tatur","doi":"10.2118/196897-ms","DOIUrl":"https://doi.org/10.2118/196897-ms","url":null,"abstract":"\u0000 This article is the first part of the geomechanical calculations performed in order to optimize the drilling and production operations of the first horizontal wells with target formation M in the Boca de Jaruco field, Republic of Cuba. Here, the analyzed data included regional geology, tectonics and stratigraphy, different types of well logging, the pressure curves while steam operations, core samples and drilling history. The outcome of this part of the work is the assessment of the current stress regime, stress directions and the stability windows for the planned wells. Moreover, the program of additional studies and logs acquisition was elaborated, as at this stage there is not enough data to confidently quantify the stress state, the core samples are not yet tested for rock's deformation and strength properties, and it is hardly possible to find carbonate bitumen deposits under development anywhere in the world which are analogous to the Boca de Jaruco field (with the sole exception of Grosmont in Northern Alberta, Canada).\u0000 After the wells are drilled (presumably by the end of 2019) and the required information is collected (such as mechanical core testing under elevated temperatures, image logs in the deviated boreholes, etc.), the second part of the work is to be performed, which would include the analysis of the drilling results and the assessment of the cap rock behavior, pore pressure and porosity-permeability changes due to steam injection.","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":"80271719","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. Martemyanov, E. Shel, V. Bratov, I. Chebyshev, G. Paderin, I. Bazyrov
An approach to determine stress field near wellbore with existing hydraulic fracture accounting for rising pressure and fluid filtration along the crack has been developed. An estimations of secondary fracture initiation time near wellbore as well as moment of primary crack growth start have been produced. Factual data about mechanical rock properties, stress state and pore fluid pressure was used. It has been shown finally that reorientation of secondary fracture in the case of vertical well is improbable during reinjection. Calculations were made with various magnitude and rate of pumping pressure increasing, value of pore pressure inside formation and main tectonic stress ratio acting at infinity. Similar analysis in the case of horizontal well demonstrated several alternative mechanisms of secondary fracture initiation: simulteniously with existing crack growth new fractures along and orthogonal to well trajectory may appear. Which of type will become dominant depends on actual geomachanical conditions and primary fracture characteristics. Obtained estimations have been compared with field observations.
{"title":"Conditions of Secondary Fracture Reorientation for Cases of Vertical and Horizontal Wells","authors":"A. Martemyanov, E. Shel, V. Bratov, I. Chebyshev, G. Paderin, I. Bazyrov","doi":"10.2118/196966-ms","DOIUrl":"https://doi.org/10.2118/196966-ms","url":null,"abstract":"\u0000 An approach to determine stress field near wellbore with existing hydraulic fracture accounting for rising pressure and fluid filtration along the crack has been developed. An estimations of secondary fracture initiation time near wellbore as well as moment of primary crack growth start have been produced. Factual data about mechanical rock properties, stress state and pore fluid pressure was used. It has been shown finally that reorientation of secondary fracture in the case of vertical well is improbable during reinjection. Calculations were made with various magnitude and rate of pumping pressure increasing, value of pore pressure inside formation and main tectonic stress ratio acting at infinity. Similar analysis in the case of horizontal well demonstrated several alternative mechanisms of secondary fracture initiation: simulteniously with existing crack growth new fractures along and orthogonal to well trajectory may appear. Which of type will become dominant depends on actual geomachanical conditions and primary fracture characteristics. Obtained estimations have been compared with field observations.","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":"85648175","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}
Hydraulic fracture complexity in unconventional formations, such as shales, has been predominantly associated with the interaction of hydraulic fractures with pre-existing natural fractures. In this study, we demonstrate a novel experimental evidence that shows complex fractures can be induced in intact specimens that are mechanically heterogeneous in the absence of any pre-existing fractures. Synthetic materials are used to cast sheet-like, porous test specimens that have strongly-bonded layers with different mechanical properties. The layered specimen is placed between two thick, transparent plates and constant, anisotropic far-field stresses are applied to the specimen. Fracturing fluid is injected in the center of the specimen, and the induced fracture trajectories are captured with high resolution digital images and subsequent image processing. First, we show that a bi-wing, planar fracture is induced in the layered specimen along the maximum far-field stress direction when the applied differential stress is relatively high. However, when the applied differential stress is relatively low, the induced fractures become complex with multiple wings and nonplanar trajectories. Fracture complexity can also arise under relatively high differential stress when the hydraulic fracture is induced in a thin layer bounded by thicker and harder layers. When the applied differential stress is zero or extremely low, the induced hydraulic fractures become notably less complex, and the fracture propagation direction becomes controlled by the specimen heterogeneity. Recent field evidence by coring through a stimulated rock volume (SRV) in the Eagle Ford Shale showed the formation of complex fractures despite the sparseness of pre-existing fractures in the cored sections of the SRV. Using well-controlled laboratory experiments, our results prove that rock heterogeneity is a plausible and important mechanism for generating complex fractures.
{"title":"Creation of Complex Hydraulic Fractures Due to Macroscopic Rock Heterogeneity","authors":"M. AlTammar, M. Sharma","doi":"10.2118/196901-ms","DOIUrl":"https://doi.org/10.2118/196901-ms","url":null,"abstract":"\u0000 Hydraulic fracture complexity in unconventional formations, such as shales, has been predominantly associated with the interaction of hydraulic fractures with pre-existing natural fractures. In this study, we demonstrate a novel experimental evidence that shows complex fractures can be induced in intact specimens that are mechanically heterogeneous in the absence of any pre-existing fractures.\u0000 Synthetic materials are used to cast sheet-like, porous test specimens that have strongly-bonded layers with different mechanical properties. The layered specimen is placed between two thick, transparent plates and constant, anisotropic far-field stresses are applied to the specimen. Fracturing fluid is injected in the center of the specimen, and the induced fracture trajectories are captured with high resolution digital images and subsequent image processing.\u0000 First, we show that a bi-wing, planar fracture is induced in the layered specimen along the maximum far-field stress direction when the applied differential stress is relatively high. However, when the applied differential stress is relatively low, the induced fractures become complex with multiple wings and nonplanar trajectories. Fracture complexity can also arise under relatively high differential stress when the hydraulic fracture is induced in a thin layer bounded by thicker and harder layers. When the applied differential stress is zero or extremely low, the induced hydraulic fractures become notably less complex, and the fracture propagation direction becomes controlled by the specimen heterogeneity.\u0000 Recent field evidence by coring through a stimulated rock volume (SRV) in the Eagle Ford Shale showed the formation of complex fractures despite the sparseness of pre-existing fractures in the cored sections of the SRV. Using well-controlled laboratory experiments, our results prove that rock heterogeneity is a plausible and important mechanism for generating complex fractures.","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":"84845774","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. Ilyasov, A. Podkorytov, A. Gudz, V. Komarov, N. Glushchenko
The main objective of this paper is to share experience obtained from waterflood implementation in unconsolidated reservoir PK1-3 with heavy oil in East-Messoyakhskoe oil field. Key geological features of PK1-3 reservoir are presented, on which attention should be paid during waterflooding organization in unconsolidated reservoir with heavy oil. Typical effects are described, which are observed during waterflooding of such reservoirs, their analysis is made, based on world experience and actual field results. The history of waterflood implementation from the design and pilot stage to the full-field implementation stage and obtained results are highlighted. Waterflooding strategy and tactics used at this field development stage are described in details: analytical tools, selection and justification of injection pressure, selection of target VRR, individual injection rates selection, investigation program, tactical waterflood management. In addition, proactive actions to improve waterflooding efficiency and field development of PK1-3 reservoir are described. We hope that our experience will be useful to colleagues - reservoir engineers who already started or only plan to start field development with waterflooding of similar fields.
{"title":"Waterflooding East-Messoyakhskoe Heavy Oil Field in Unconsolidated Reservoir – Challenges and Proactivity","authors":"I. Ilyasov, A. Podkorytov, A. Gudz, V. Komarov, N. Glushchenko","doi":"10.2118/196752-ms","DOIUrl":"https://doi.org/10.2118/196752-ms","url":null,"abstract":"The main objective of this paper is to share experience obtained from waterflood implementation in unconsolidated reservoir PK1-3 with heavy oil in East-Messoyakhskoe oil field. Key geological features of PK1-3 reservoir are presented, on which attention should be paid during waterflooding organization in unconsolidated reservoir with heavy oil. Typical effects are described, which are observed during waterflooding of such reservoirs, their analysis is made, based on world experience and actual field results. The history of waterflood implementation from the design and pilot stage to the full-field implementation stage and obtained results are highlighted. Waterflooding strategy and tactics used at this field development stage are described in details: analytical tools, selection and justification of injection pressure, selection of target VRR, individual injection rates selection, investigation program, tactical waterflood management. In addition, proactive actions to improve waterflooding efficiency and field development of PK1-3 reservoir are described. We hope that our experience will be useful to colleagues - reservoir engineers who already started or only plan to start field development with waterflooding of similar fields.","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":"82818743","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. Overin, M. Samoilov, S. Kudrya, Konstantin Baidyukov
Accelerated multi-stage hydraulic fracturing at the Samotlor Field significantly contributes to the reduction of time and financial costs for well construction and well interventions. High friction pressure loss is one of the main causes of complications, extra process operations, and, as a result, extra time and financial costs for multi-stage hydraulic fracturing with selective packers and burst port collars. A comprehensive analysis of MS frac data and testing of new approaches to mini-frac confirmed a potential significant reduction in MS frac costs at the Samotlor Field. The work consisted of three stages. The first stage included the following: Compared the data from wellhead and downhole gaugesAnalyzed in-situ temperature profileAnalyzed the results of Step Down Tests (SDT)Identified patterns of pressure changes in the bottomhole and near-wellbore zonesAnalyzed the causes of high working pressures at collar activation stages. The second stage covered a mini-frac pilot against a modified approach: Cancelled Step Down TestsIncreased planned fluid ratesCancelled a mini-frac with proppantDetermined methods for optimizing the main hydraulic fracturing. The third stage confirmed the efficiency of new approaches to multi-stage hydraulic fracturing with a selective packer and burst port collars at the Samotlor field. The paper analyzes the data on wells with the following types of completions: 34 wells with cemented liners14 wells with non-cemented liners with swellable packers. 330 hydraulic fracturing stages were analyzed. The sensitivities of friction changes in the bottomhole zone and the frac collar zone to various factors were evaluated: Number and types of injection jobsFluid flow rateEffect of hydraulic fracturing fluid and abrasive effects of proppant. The design features of internal-flush sleeves with burst port collars were studied and factors affecting fluid flow restrictions in the near-wellbore formation zone were determined. Based on the analysis, recommendations were made to optimize injection jobs during a pilot and the main hydraulic fracturing. Pilot jobs were carried out in 40 wells, which included 150 stages without traditionally performed test injections (a step-down test with a decrease in flow rate and a calibration test on crosslinked fluid with proppant). The tested methods allowed to accelerate the hydraulic fracturing process, reduce the volume of injected fluid, speed up the decision-making process related to field jobs, which led to accelerated operations and reduced cost of multi-stage hydraulic fracturing at the Samotlor Field. The novelty of the work lies in the development and justification of an individual approach to a set of test studies and the types of changes in hydraulic fracturing programs depending on subsurface and engineering factors, working pressure profile, and estimated friction losses. As mentioned earlier, the proposed approach will significantly reduce the time and financial costs of mul
{"title":"Multistage Stimulation: Fracturing Optimization at Samotlorskoe Field","authors":"A. Overin, M. Samoilov, S. Kudrya, Konstantin Baidyukov","doi":"10.2118/196961-ms","DOIUrl":"https://doi.org/10.2118/196961-ms","url":null,"abstract":"\u0000 Accelerated multi-stage hydraulic fracturing at the Samotlor Field significantly contributes to the reduction of time and financial costs for well construction and well interventions. High friction pressure loss is one of the main causes of complications, extra process operations, and, as a result, extra time and financial costs for multi-stage hydraulic fracturing with selective packers and burst port collars. A comprehensive analysis of MS frac data and testing of new approaches to mini-frac confirmed a potential significant reduction in MS frac costs at the Samotlor Field.\u0000 The work consisted of three stages. The first stage included the following: Compared the data from wellhead and downhole gaugesAnalyzed in-situ temperature profileAnalyzed the results of Step Down Tests (SDT)Identified patterns of pressure changes in the bottomhole and near-wellbore zonesAnalyzed the causes of high working pressures at collar activation stages.\u0000 The second stage covered a mini-frac pilot against a modified approach: Cancelled Step Down TestsIncreased planned fluid ratesCancelled a mini-frac with proppantDetermined methods for optimizing the main hydraulic fracturing.\u0000 The third stage confirmed the efficiency of new approaches to multi-stage hydraulic fracturing with a selective packer and burst port collars at the Samotlor field.\u0000 The paper analyzes the data on wells with the following types of completions: 34 wells with cemented liners14 wells with non-cemented liners with swellable packers.\u0000 330 hydraulic fracturing stages were analyzed. The sensitivities of friction changes in the bottomhole zone and the frac collar zone to various factors were evaluated: Number and types of injection jobsFluid flow rateEffect of hydraulic fracturing fluid and abrasive effects of proppant.\u0000 The design features of internal-flush sleeves with burst port collars were studied and factors affecting fluid flow restrictions in the near-wellbore formation zone were determined. Based on the analysis, recommendations were made to optimize injection jobs during a pilot and the main hydraulic fracturing. Pilot jobs were carried out in 40 wells, which included 150 stages without traditionally performed test injections (a step-down test with a decrease in flow rate and a calibration test on crosslinked fluid with proppant). The tested methods allowed to accelerate the hydraulic fracturing process, reduce the volume of injected fluid, speed up the decision-making process related to field jobs, which led to accelerated operations and reduced cost of multi-stage hydraulic fracturing at the Samotlor Field.\u0000 The novelty of the work lies in the development and justification of an individual approach to a set of test studies and the types of changes in hydraulic fracturing programs depending on subsurface and engineering factors, working pressure profile, and estimated friction losses. As mentioned earlier, the proposed approach will significantly reduce the time and financial costs of mul","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":"80418397","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 cost-effective development of low-permeability hydrocarbon formations of small thickness requires horizontal wells with multi-stage hydraulic fracturing (MS-Frac). The presence of higher or lower layers that are water-saturated and weak barriers to height growth imposes a restriction on the desirable geometry of the fracture to prevent a breakthrough into a flooded interval. Combining several methods of fracture height restriction and controlling such height can improve the efficiency of multi-stage hydraulic fracturing. The first technology to control the effective pressure was based on changing fracturing fluid rheology and resulted in a decrease in the net pressure and the fracture height. The main treatment buffer utilized a hybrid fluid design. The second technology used to limit the height of the fracture was based on creating artificial barriers inside the fracture that restrict height growth. In this case, a special mixture of proppants was pumped before the primary proppant-laden fracturing main stage. The construction of a horizontal well with a multizone completion implies the possibility of carrying out small volume multistage fracturing to prevent breakthrough into a water-saturated interval, creating an effective drainage zone. For the first time in the given field, MS-Frac was performed using combined technologies and techniques for fracture height growth restriction. The operations demonstrated successful results of horizontal multizone well treatments, where the rheology and fluid rate control methods were used to restrict the fracture geometry growth, and proppant slugs were used to create artificial barriers to arrest the fracture height growth.
{"title":"Improving the Effectiveness of Multi-Stage Hydraulic Fracturing in Horizontal Wells by Fracture Height Restriction","authors":"A. Valiullin, V. Astafyev, I. Osipov","doi":"10.2118/196986-ms","DOIUrl":"https://doi.org/10.2118/196986-ms","url":null,"abstract":"\u0000 The cost-effective development of low-permeability hydrocarbon formations of small thickness requires horizontal wells with multi-stage hydraulic fracturing (MS-Frac). The presence of higher or lower layers that are water-saturated and weak barriers to height growth imposes a restriction on the desirable geometry of the fracture to prevent a breakthrough into a flooded interval. Combining several methods of fracture height restriction and controlling such height can improve the efficiency of multi-stage hydraulic fracturing. The first technology to control the effective pressure was based on changing fracturing fluid rheology and resulted in a decrease in the net pressure and the fracture height. The main treatment buffer utilized a hybrid fluid design. The second technology used to limit the height of the fracture was based on creating artificial barriers inside the fracture that restrict height growth. In this case, a special mixture of proppants was pumped before the primary proppant-laden fracturing main stage. The construction of a horizontal well with a multizone completion implies the possibility of carrying out small volume multistage fracturing to prevent breakthrough into a water-saturated interval, creating an effective drainage zone. For the first time in the given field, MS-Frac was performed using combined technologies and techniques for fracture height growth restriction. The operations demonstrated successful results of horizontal multizone well treatments, where the rheology and fluid rate control methods were used to restrict the fracture geometry growth, and proppant slugs were used to create artificial barriers to arrest the fracture height growth.","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":"75793613","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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