Aishwarya Srinivasan, Joseph Mjehovich, K. Wu, G. Jin, Wen Wang, G. Moridis
Understanding fracture height growth is critical for optimizing hydraulic fracture treatments and field development. In recent years, low-frequency distributed acoustic sensing (LF-DAS) has become a popular tool for monitoring strain changes during hydraulic fracturing. While LF-DAS data from vertical monitoring wells (VMWs) can be used to determine fracture height, measurements from the vertical section of horizontal wells may have the potential to capture fracture height growth. The objectives of this study are (1) to apply three methods—(a) using the vertical section of horizontal fiber measurements, (b) using the vertical fiber measurements, and (c) using the horizontal section of horizontal fiber measurements—to determine the fracture height using the Hydraulic Fracturing Test Site 2 (HFTS-2) data set and (2) to demonstrate the reliability of using LF-DAS measurements from the vertical section of horizontal fibers for fracture height determination. In an effort to determine the fracture height from the HFTS-2 data set using the three methods, we demonstrate the reliability of the height prediction using strain measurements in the vertical section of the horizontal monitoring well (VS-HMW). First, we analyze the measurements from the vertical section of the horizontal fiber (B3H) during the stimulation of the heel-most stages of the horizontal wells (B1H, B2H, and B4H). Second, we analyze the measurements from the VMW (B5PH) during the stimulations of B1H, B2H, and B4H. Third, we use a geomechanical inversion algorithm to obtain height estimates from the horizontal section of the LF-DAS measurements at B3H during B1H, B2H, and B4H stimulations. The fracture height is determined based on the transition of the extension-compression zone in the LF-DAS measurements from the vertical sections. The height estimates obtained using the three methods are compared and found to be consistent in the six well pairs we analyzed. The LF-DAS measurements from the vertical well B5PH provide a complete height profile, while measurements from the vertical section capture fracture growth from the upper tip of the fracture to the landing depth of the horizontal well. The fracture height estimates obtained from our inversion algorithm represent the average height value of all fracture hits at the chosen stage. This study demonstrates the potential to determine fracture height growth using LF-DAS measurements in the vertical section of a horizontal well, thus avoiding the cost associated with drilling VMWs to obtain fracture heights.
{"title":"Fracture Height Quantification from Vertical and Horizontal Section Fiber Measurements: A Comprehensive Study Using LF-DAS Measurements from HFTS-2 Data Set","authors":"Aishwarya Srinivasan, Joseph Mjehovich, K. Wu, G. Jin, Wen Wang, G. Moridis","doi":"10.2118/219488-pa","DOIUrl":"https://doi.org/10.2118/219488-pa","url":null,"abstract":"\u0000 Understanding fracture height growth is critical for optimizing hydraulic fracture treatments and field development. In recent years, low-frequency distributed acoustic sensing (LF-DAS) has become a popular tool for monitoring strain changes during hydraulic fracturing. While LF-DAS data from vertical monitoring wells (VMWs) can be used to determine fracture height, measurements from the vertical section of horizontal wells may have the potential to capture fracture height growth. The objectives of this study are (1) to apply three methods—(a) using the vertical section of horizontal fiber measurements, (b) using the vertical fiber measurements, and (c) using the horizontal section of horizontal fiber measurements—to determine the fracture height using the Hydraulic Fracturing Test Site 2 (HFTS-2) data set and (2) to demonstrate the reliability of using LF-DAS measurements from the vertical section of horizontal fibers for fracture height determination.\u0000 In an effort to determine the fracture height from the HFTS-2 data set using the three methods, we demonstrate the reliability of the height prediction using strain measurements in the vertical section of the horizontal monitoring well (VS-HMW). First, we analyze the measurements from the vertical section of the horizontal fiber (B3H) during the stimulation of the heel-most stages of the horizontal wells (B1H, B2H, and B4H). Second, we analyze the measurements from the VMW (B5PH) during the stimulations of B1H, B2H, and B4H. Third, we use a geomechanical inversion algorithm to obtain height estimates from the horizontal section of the LF-DAS measurements at B3H during B1H, B2H, and B4H stimulations.\u0000 The fracture height is determined based on the transition of the extension-compression zone in the LF-DAS measurements from the vertical sections. The height estimates obtained using the three methods are compared and found to be consistent in the six well pairs we analyzed. The LF-DAS measurements from the vertical well B5PH provide a complete height profile, while measurements from the vertical section capture fracture growth from the upper tip of the fracture to the landing depth of the horizontal well. The fracture height estimates obtained from our inversion algorithm represent the average height value of all fracture hits at the chosen stage. This study demonstrates the potential to determine fracture height growth using LF-DAS measurements in the vertical section of a horizontal well, thus avoiding the cost associated with drilling VMWs to obtain fracture heights.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140273604","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
High-voltage electric pulse rock-breaking (HVEPB) has proved to be a novel and inexpensive method of breaking rock regardless of rock composition, but the design of the electrode drill bit lacks a theoretical basis. In this paper, we first establish a plasma channel model for electric breakdown and a numerical rock-breaking model for HVEPB, which can simulate the rock electrical breakdown plasma channel and the effect of different electrode drill bits on HVEPB. Second, we analyze the effects of different electrode arrangement structures and high-voltage electrode angles on plasma channels and the effects of internal cracks and rock-breaking processes through numerical simulation. Finally, we describe HVEPB experiments conducted using electrode drill bits with different electrode arrangement structures and high-voltage electrode angles, and with the boreholes reconstructed in three dimensions to analyze the effects of different electrode arrangement structures and high-voltage electrode angles on HVEPB drilling. The results show that the effects of the electrode drill bits on HVEPB are reflected mainly in the difference between the plasma channel and shock wave. Different electrode arrangement structures and high-voltage electrode angles result in different electric fields and energy utilization efficiencies within the rock, resulting in different shock waves and differences in the depth, shapes, and penetration of the plasma channels. The simulations and experimental studies in this paper can guide and optimize the design of the discharge tool to upgrade the drilling efficiency of HVEPB.
{"title":"Research on the Effects of an Electrode Drill Bit during the Rock Drilling Process by High-Voltage Electric Pulse","authors":"Longchen Duan, Xianao Liu, Changping Li, Jifeng Kang, Di Zhang, Zhong Yuan","doi":"10.2118/219735-pa","DOIUrl":"https://doi.org/10.2118/219735-pa","url":null,"abstract":"\u0000 High-voltage electric pulse rock-breaking (HVEPB) has proved to be a novel and inexpensive method of breaking rock regardless of rock composition, but the design of the electrode drill bit lacks a theoretical basis. In this paper, we first establish a plasma channel model for electric breakdown and a numerical rock-breaking model for HVEPB, which can simulate the rock electrical breakdown plasma channel and the effect of different electrode drill bits on HVEPB. Second, we analyze the effects of different electrode arrangement structures and high-voltage electrode angles on plasma channels and the effects of internal cracks and rock-breaking processes through numerical simulation. Finally, we describe HVEPB experiments conducted using electrode drill bits with different electrode arrangement structures and high-voltage electrode angles, and with the boreholes reconstructed in three dimensions to analyze the effects of different electrode arrangement structures and high-voltage electrode angles on HVEPB drilling. The results show that the effects of the electrode drill bits on HVEPB are reflected mainly in the difference between the plasma channel and shock wave. Different electrode arrangement structures and high-voltage electrode angles result in different electric fields and energy utilization efficiencies within the rock, resulting in different shock waves and differences in the depth, shapes, and penetration of the plasma channels. The simulations and experimental studies in this paper can guide and optimize the design of the discharge tool to upgrade the drilling efficiency of HVEPB.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140272467","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The differences in the transport behavior and adsorption capacity of different gases in coal play crucial roles in the evolution of coal permeability. Previous studies of coreflooding experiments failed to explain the mechanism of gas flow and have attributed the variation in gas seepage flux (flow rate) at the beginning of the experiment to the change in effective stress, while the differences in the microscopic properties of different gases, such as molar mass, molecular diameter, mean molecular free path, and molecular collision frequency, were ignored. To research the effect of these gas properties on seepage flux while circumventing the effective stress, coreflooding experiments with helium (He), argon (Ar), nitrogen (N2), methane (CH4), and carbon dioxide (CO2) were designed. The results show that the gas transport velocity in coal is affected by the combination of molecular collision frequency and dynamic viscosity, and the transport velocities follow the order of ν (CH4) > ν (He) > ν (N2) > ν (CO2) > ν (Ar). A permeability equation corrected by the molecular collision frequency is proposed to eliminate differences in the permeabilities measured with different gases. The adsorption of different gases on the coal matrix causes different degrees of swelling, and the adsorption-induced swelling strains follow the order of ε (CO2) > ε (CH4) > ε (N2) > ε (Ar) > ε (He). The reduction in seepage flux and irreversible alterations in pore structure caused by adsorption-induced swelling are positively correlated with their adsorption capacities. The gas seepage fluxes after adsorption equilibrium of coal follow the order of Q (He) > Q (CH4) >Q (N2) > Q (Ar) > Q (CO2). Like supercritical CO2 (ScCO2), conventional CO2 can also dissolve the organic matter in coal. The organic molecules close to the walls of the cleats along the direction of gas flow are preferentially dissolved by CO2, and the gas seepage flux increases when the dissolution effect on the cleat width is greater than that on adsorption swelling.
{"title":"Experimental Study of the Effect of Molecular Collision Frequency and Adsorption Capacity on Gas Seepage Flux in Coal","authors":"Yang Gao, Qingchun Yu","doi":"10.2118/219733-pa","DOIUrl":"https://doi.org/10.2118/219733-pa","url":null,"abstract":"\u0000 The differences in the transport behavior and adsorption capacity of different gases in coal play crucial roles in the evolution of coal permeability. Previous studies of coreflooding experiments failed to explain the mechanism of gas flow and have attributed the variation in gas seepage flux (flow rate) at the beginning of the experiment to the change in effective stress, while the differences in the microscopic properties of different gases, such as molar mass, molecular diameter, mean molecular free path, and molecular collision frequency, were ignored. To research the effect of these gas properties on seepage flux while circumventing the effective stress, coreflooding experiments with helium (He), argon (Ar), nitrogen (N2), methane (CH4), and carbon dioxide (CO2) were designed. The results show that the gas transport velocity in coal is affected by the combination of molecular collision frequency and dynamic viscosity, and the transport velocities follow the order of ν (CH4) > ν (He) > ν (N2) > ν (CO2) > ν (Ar). A permeability equation corrected by the molecular collision frequency is proposed to eliminate differences in the permeabilities measured with different gases. The adsorption of different gases on the coal matrix causes different degrees of swelling, and the adsorption-induced swelling strains follow the order of ε (CO2) > ε (CH4) > ε (N2) > ε (Ar) > ε (He). The reduction in seepage flux and irreversible alterations in pore structure caused by adsorption-induced swelling are positively correlated with their adsorption capacities. The gas seepage fluxes after adsorption equilibrium of coal follow the order of Q (He) > Q (CH4) >Q (N2) > Q (Ar) > Q (CO2). Like supercritical CO2 (ScCO2), conventional CO2 can also dissolve the organic matter in coal. The organic molecules close to the walls of the cleats along the direction of gas flow are preferentially dissolved by CO2, and the gas seepage flux increases when the dissolution effect on the cleat width is greater than that on adsorption swelling.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140405321","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Miguel Gonzalez, Subhash Ayirala, Lyla Maskeen, Abdulkareem AlSofi
There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids in the laboratory. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. In the polymer fluids, the measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s−1, closer to the solvent viscosity values. However, the predicted rheometer viscosity vs. QTF-measured viscosity showed a distinct exponential correlation (R2=0.9997), allowing for an empirical calibration between the two viscometers for fluids having the same solvent and polymer compositions. The QTF sensors produced acceptable viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field and predicted field sample viscosities with less than 1–2 cp (or 10–20%) error from the rheometer data. Results were validated based on separate independent tests where the devices were used to measure the viscosity of Newtonian fluids and non-Newtonian polymer fluids in a series of consecutive dip tests, simulating more realistic usage. These devices can be used to measure either the “relative” viscosity changes from a polymer solution prior and post-injection or to measure a “calibrated” viscosity via empirical exponential correlation. The compact QTF sensors developed in this study can be easily integrated into portable systems for laboratory or wellsite deployment as well as logging tools for downhole deployment. This work also demonstrates the ability of these QTF devices to make sensitive viscosity measurements at high-frequencies, opening opportunities for their use in high-frequency rheology studies of EOR fluids.
{"title":"Compact Viscosity Sensors for Downhole Enhanced Oil Recovery Polymer Fluid Degradation Monitoring","authors":"Miguel Gonzalez, Subhash Ayirala, Lyla Maskeen, Abdulkareem AlSofi","doi":"10.2118/209430-pa","DOIUrl":"https://doi.org/10.2118/209430-pa","url":null,"abstract":"\u0000 There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids in the laboratory. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. In the polymer fluids, the measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s−1, closer to the solvent viscosity values. However, the predicted rheometer viscosity vs. QTF-measured viscosity showed a distinct exponential correlation (R2=0.9997), allowing for an empirical calibration between the two viscometers for fluids having the same solvent and polymer compositions. The QTF sensors produced acceptable viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field and predicted field sample viscosities with less than 1–2 cp (or 10–20%) error from the rheometer data. Results were validated based on separate independent tests where the devices were used to measure the viscosity of Newtonian fluids and non-Newtonian polymer fluids in a series of consecutive dip tests, simulating more realistic usage. These devices can be used to measure either the “relative” viscosity changes from a polymer solution prior and post-injection or to measure a “calibrated” viscosity via empirical exponential correlation. The compact QTF sensors developed in this study can be easily integrated into portable systems for laboratory or wellsite deployment as well as logging tools for downhole deployment. This work also demonstrates the ability of these QTF devices to make sensitive viscosity measurements at high-frequencies, opening opportunities for their use in high-frequency rheology studies of EOR fluids.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140280199","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In shale gas drilling operations, oil-based drilling fluids have proved to be effective in addressing the issue of shale reservoir hydration expansion, serving as the primary working fluid for complex subsurface shale formations. However, the presence of shale laminations and the development of microfractures with varying widths require drilling fluids with excellent sealing capabilities. In this study, a comprehensive investigation was conducted to develop a drilling fluid system with broad-spectrum high-sealing performance. The porosity of bridging particles was determined by using the Archimedean drainage method. The bridging particle size and quantity at each level were meticulously designed through leveraging the Horsfield close-packing theory. The incorporation of deformable nanoscale polymer sealing materials further enhanced the sealing performance of the drilling fluid system. Additionally, hydrophobic nanoscale silica particles were introduced as coemulsifier to prepare Pickering emulsions, thereby improving emulsion stability and enhancing particle-size distribution for improved sealing. Through formulation optimization, a drilling fluid system with broad-spectrum, high-sealing performance capabilities was developed. The study revealed a reduction in porosity of closely packed bridging particles from 35.36% to 11.38%. The drilling fluid system exhibited a remarkable sealing efficiency of 99.2% for microfractures in the 1–10 μm range and 95.8% for microfractures in the 30–50 μm range. Furthermore, it demonstrated excellent sedimentation stability, with a sedimentation factor of less than 0.52 after 48 hours of static sedimentation at 150°C. The drilling fluid system also exhibited favorable rheological, lubrication, and inhibition properties, thus meeting the demands of field applications.
{"title":"The Investigation of Broad-Spectrum Sealing Drilling Fluid Based on Horsfield Close-Packing Theory","authors":"Haoan Dong, Zhiyong Li, Xiangyu Meng, Xue Peng, Rongxin Ma, Haotian Cen, Ruixing Xu","doi":"10.2118/219489-pa","DOIUrl":"https://doi.org/10.2118/219489-pa","url":null,"abstract":"\u0000 In shale gas drilling operations, oil-based drilling fluids have proved to be effective in addressing the issue of shale reservoir hydration expansion, serving as the primary working fluid for complex subsurface shale formations. However, the presence of shale laminations and the development of microfractures with varying widths require drilling fluids with excellent sealing capabilities. In this study, a comprehensive investigation was conducted to develop a drilling fluid system with broad-spectrum high-sealing performance. The porosity of bridging particles was determined by using the Archimedean drainage method. The bridging particle size and quantity at each level were meticulously designed through leveraging the Horsfield close-packing theory. The incorporation of deformable nanoscale polymer sealing materials further enhanced the sealing performance of the drilling fluid system. Additionally, hydrophobic nanoscale silica particles were introduced as coemulsifier to prepare Pickering emulsions, thereby improving emulsion stability and enhancing particle-size distribution for improved sealing. Through formulation optimization, a drilling fluid system with broad-spectrum, high-sealing performance capabilities was developed. The study revealed a reduction in porosity of closely packed bridging particles from 35.36% to 11.38%. The drilling fluid system exhibited a remarkable sealing efficiency of 99.2% for microfractures in the 1–10 μm range and 95.8% for microfractures in the 30–50 μm range. Furthermore, it demonstrated excellent sedimentation stability, with a sedimentation factor of less than 0.52 after 48 hours of static sedimentation at 150°C. The drilling fluid system also exhibited favorable rheological, lubrication, and inhibition properties, thus meeting the demands of field applications.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140269814","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Fangxuan Chen, Shihao Wang, M. Dejam, H. Nasrabadi
As a clean energy carrier, hydrogen (H2) is considered an indispensable part of the energy transition roadmap. To meet increasing energy demand, extremely large storage capacities are required. Previous studies have focused on underground H2 storage in conventional depleted gas reservoirs, salt caverns, and saline aquifers. The increasing number of depleted shale gas reservoirs may be good candidates for H2 storage. In this work, we analyze the potential of H2 storage in depleted gas reservoirs using Monte Carlo (MC) simulations. The competitive adsorption of a methane-hydrogen (C1-H2) system under nanoscale conditions is investigated, including the effects of pore size, temperature, pressure, boundary material, and fluid composition. Our results show that C1 is preferentially adsorbed in a C1-H2 system. C1 forms the adsorption layer near the boundary surface, while H2 molecules are freely distributed in the pore. The fluid distribution indicates that H2 can be easily produced during H2 recovery processes, which contributes to H2 storage in depleted shale gas reservoirs. In addition, the effect of water on C1-H2 competitive adsorption is analyzed. The strong interactions between water and boundary atoms force C1 molecules away from the adsorbed region. This work provides a foundation for hydrogen storage in depleted shale gas reservoirs at a molecular level.
{"title":"Molecular Simulation of Competitive Adsorption of Hydrogen and Methane: Analysis of Hydrogen Storage Feasibility in Depleted Shale Gas Reservoirs","authors":"Fangxuan Chen, Shihao Wang, M. Dejam, H. Nasrabadi","doi":"10.2118/212218-pa","DOIUrl":"https://doi.org/10.2118/212218-pa","url":null,"abstract":"\u0000 As a clean energy carrier, hydrogen (H2) is considered an indispensable part of the energy transition roadmap. To meet increasing energy demand, extremely large storage capacities are required. Previous studies have focused on underground H2 storage in conventional depleted gas reservoirs, salt caverns, and saline aquifers. The increasing number of depleted shale gas reservoirs may be good candidates for H2 storage. In this work, we analyze the potential of H2 storage in depleted gas reservoirs using Monte Carlo (MC) simulations. The competitive adsorption of a methane-hydrogen (C1-H2) system under nanoscale conditions is investigated, including the effects of pore size, temperature, pressure, boundary material, and fluid composition. Our results show that C1 is preferentially adsorbed in a C1-H2 system. C1 forms the adsorption layer near the boundary surface, while H2 molecules are freely distributed in the pore. The fluid distribution indicates that H2 can be easily produced during H2 recovery processes, which contributes to H2 storage in depleted shale gas reservoirs. In addition, the effect of water on C1-H2 competitive adsorption is analyzed. The strong interactions between water and boundary atoms force C1 molecules away from the adsorbed region. This work provides a foundation for hydrogen storage in depleted shale gas reservoirs at a molecular level.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140277391","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study presents a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the rate transient analysis of flowback and production data. The proposed method includes straightline analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and nonstimulated reservoir volume (NSRV) domains. HF closure dynamics are characterized by two key parameters, which are pressure-dependent permeability and porosity controlled by fracture permeability modulus and compressibility. The above techniques are combined into a generalized workflow to estimate iteratively the five parameters (including four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, and MHM), and phases (water and hydrocarbon phase). We used flowback and production data from a shale gas well in the US and a shale oil well in China to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties [initial fracture pore volume (PV) and permeability] and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability modulus, and compressibility demonstrates the applicability of the comprehensive method in quantifying HF dynamics. The field application results suggest a reduction of the fracture PV by 15% and 20%, and a reduction of the fracture permeability by 80% and 90% for shale gas and shale oil wells, respectively.
{"title":"A Generalized Method for Dynamic Fracture Characterization Using Two-Phase Rate Transient Analysis of Flowback and Production Data","authors":"Guoqing Sun, Zhengxin Zhang, Changhe Mu, Chuncheng Liu, Chao Deng, Weikai Li, Weiran Hu","doi":"10.2118/215213-pa","DOIUrl":"https://doi.org/10.2118/215213-pa","url":null,"abstract":"\u0000 This study presents a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the rate transient analysis of flowback and production data.\u0000 The proposed method includes straightline analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and nonstimulated reservoir volume (NSRV) domains. HF closure dynamics are characterized by two key parameters, which are pressure-dependent permeability and porosity controlled by fracture permeability modulus and compressibility. The above techniques are combined into a generalized workflow to estimate iteratively the five parameters (including four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, and MHM), and phases (water and hydrocarbon phase).\u0000 We used flowback and production data from a shale gas well in the US and a shale oil well in China to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties [initial fracture pore volume (PV) and permeability] and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability modulus, and compressibility demonstrates the applicability of the comprehensive method in quantifying HF dynamics. The field application results suggest a reduction of the fracture PV by 15% and 20%, and a reduction of the fracture permeability by 80% and 90% for shale gas and shale oil wells, respectively.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140282894","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Haoan Dong, Zhiyong Li, Dong Xu, Lili Yan, Lihui Wang, Yan Ye
Nanoscale plugging materials are commonly used in the petroleum industry to seal microfractures and pores within shale formations, thereby maintaining wellbore stability and preventing drilling accidents caused by formation collapse. However, the influence of inorganic salts present in the formation and drilling fluids on the dispersion properties of nanoscale plugging materials often affects their sealing performance. In this study, we focus on investigating the influence of three commonly encountered inorganic salts in the drilling process—sodium chloride (NaCl), potassium chloride (KCl), and calcium chloride (CaCl2)—on the dispersibility and sealing performance of commonly used nanoscale plugging materials such as nanosilica and nanoemulsions in shale formations, exploring the dispersion and sealing mechanisms. Zeta potential is used as a characterization parameter, and molecular dynamics simulations are used to study the effects and mechanisms of inorganic salt ions on the dispersion of plugging materials. Filtration and pressure transmission experiments are conducted to investigate changes in their sealing performance. Scanning electron microscopy (SEM) is used to observe the microstructure of the formed filter cake, providing insights into the dispersion and sealing mechanisms. The results reveal that nanosilica agglomerates at zeta potentials ranging from −18 mV to −15.5 mV, resulting in an increase in filtration volume from 93.3 mL to 171.1 mL and downstream stable pressure transmission rising from 330.98 psi to 551.98 psi. Nanosilica (modified with KH570) agglomerates at zeta potentials of −10.3 mV to −9.9 mV, leading to an increase in filtration volume from 93.1 mL to 171 mL and downstream stable pressure transmission rising from 326.98 psi to 553.35 psi. The average gyration radius of the KH570 molecule decreases from 0.347 nm to 0.337 nm under the influence of inorganic salts. In contrast, the dispersion stability of nanoscale emulsions is independent of zeta potential; however, under the influence of inorganic salts, the filtration volume increases from 92.2 mL to 170.9 mL and downstream stable pressure transmission rises from 293.03 psi to 550.98 psi. The average gyration radius of nanoscale emulsion monomer molecules decreases from 0.340 nm to 0.336 nm under the influence of inorganic salts. Microscopic examination of filter-cake morphology shows that inorganic salts not only affect dispersion stability, leading to the aggregation of nanomaterials and influencing sealing performance, but also reduce the deformability of organic particles, thereby affecting sealing performance. The properties obtained in this study provide theoretical references for the sealing performance of nanomaterials in drilling fluids, offering significant value for researchers and field engineers in selecting nanoscale plugging materials for shale formations.
{"title":"Study on the Dispersion Stability and Sealing Performance of Nanoscale Plugging Materials for Shale Formations","authors":"Haoan Dong, Zhiyong Li, Dong Xu, Lili Yan, Lihui Wang, Yan Ye","doi":"10.2118/219736-pa","DOIUrl":"https://doi.org/10.2118/219736-pa","url":null,"abstract":"\u0000 Nanoscale plugging materials are commonly used in the petroleum industry to seal microfractures and pores within shale formations, thereby maintaining wellbore stability and preventing drilling accidents caused by formation collapse. However, the influence of inorganic salts present in the formation and drilling fluids on the dispersion properties of nanoscale plugging materials often affects their sealing performance. In this study, we focus on investigating the influence of three commonly encountered inorganic salts in the drilling process—sodium chloride (NaCl), potassium chloride (KCl), and calcium chloride (CaCl2)—on the dispersibility and sealing performance of commonly used nanoscale plugging materials such as nanosilica and nanoemulsions in shale formations, exploring the dispersion and sealing mechanisms. Zeta potential is used as a characterization parameter, and molecular dynamics simulations are used to study the effects and mechanisms of inorganic salt ions on the dispersion of plugging materials. Filtration and pressure transmission experiments are conducted to investigate changes in their sealing performance. Scanning electron microscopy (SEM) is used to observe the microstructure of the formed filter cake, providing insights into the dispersion and sealing mechanisms. The results reveal that nanosilica agglomerates at zeta potentials ranging from −18 mV to −15.5 mV, resulting in an increase in filtration volume from 93.3 mL to 171.1 mL and downstream stable pressure transmission rising from 330.98 psi to 551.98 psi. Nanosilica (modified with KH570) agglomerates at zeta potentials of −10.3 mV to −9.9 mV, leading to an increase in filtration volume from 93.1 mL to 171 mL and downstream stable pressure transmission rising from 326.98 psi to 553.35 psi. The average gyration radius of the KH570 molecule decreases from 0.347 nm to 0.337 nm under the influence of inorganic salts. In contrast, the dispersion stability of nanoscale emulsions is independent of zeta potential; however, under the influence of inorganic salts, the filtration volume increases from 92.2 mL to 170.9 mL and downstream stable pressure transmission rises from 293.03 psi to 550.98 psi. The average gyration radius of nanoscale emulsion monomer molecules decreases from 0.340 nm to 0.336 nm under the influence of inorganic salts. Microscopic examination of filter-cake morphology shows that inorganic salts not only affect dispersion stability, leading to the aggregation of nanomaterials and influencing sealing performance, but also reduce the deformability of organic particles, thereby affecting sealing performance. The properties obtained in this study provide theoretical references for the sealing performance of nanomaterials in drilling fluids, offering significant value for researchers and field engineers in selecting nanoscale plugging materials for shale formations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140403227","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study focuses on the prediction of the production-inflow profile of a well producing a single-phase flow of slightly compressible fluid (water or oil flow) in a multilayered system using the layer permeability and skin values estimated by history matching spatial and temporal temperature and/or pressure data sets along the completion interval. Such data may be acquired by wireline formation testing, production-logging-tool (PLT), or distributed temperature sensing (DTS) fiber-optic cables. We use an in-house thermal, transient coupled reservoir/wellbore simulator developed during this study. It solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The effects of the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection are all included for predicting the flow profiles across the wellbore. The results from our in-house simulator are verified with the results from a commercial simulator for the single-phase fluid flow of a vertical well producing geothermal brine and oil in a two-zone multilayer system. We also compare the results from our rigorous transient coupled wellbore/reservoir model with the results from a model assuming steady-state thermal wellbore model used in the previous studies. We find that the steady-state thermal wellbore model used in the previous studies that ignore accumulation terms in mass, momentum, and thermal energy balances is a reasonably accurate model for predicting wellbore pressures and temperatures when it is coupled with a nonisothermal reservoir model for slightly compressible fluid because the transient effect in the wellbore is less important with the slightly compressible fluid. We investigate the nonlinear parameter estimation problem based on the use of single or multiple observed temperature and/or pressure (if available) profiles recorded spatially inside the wellbore and at the sandface. The purpose is to identify if the wellbore or sandface data profiles are more useful to accurately estimate the permeability and skin information and predict a production-inflow profile of the well depending on the representation of an actual multilayer system by a reduced-layered or fine-layered model. We show that using an upscaled-layered model (e.g., representing each heterogeneous layer with a lumped single layer with uniform permeability and skin) provides estimates that are more toward the thickness-average permeability and skin factors of the layers and may not provide a good prediction of the well’s production-inflow profile. We show that including the sandface temperature data in regression worsens, while the use of wellbore temperature data sets improves the quality of parameter estimation if an upscaled multilayered model is used. We also show that regressing on multiple temperature profiles, preferably at the sandface, alone could be used to predict the production-inflow profile accurately if a “fine” multilayered heterogeneous
{"title":"Prediction of Production-Inflow Profile of a Well Producing Single-Phase Flow of Slightly Compressible Fluid from Multilayer Systems by Temperature and/or Pressure Transient Data","authors":"C. Alan, Murat Cinar, Mustafa Onur","doi":"10.2118/214384-pa","DOIUrl":"https://doi.org/10.2118/214384-pa","url":null,"abstract":"\u0000 This study focuses on the prediction of the production-inflow profile of a well producing a single-phase flow of slightly compressible fluid (water or oil flow) in a multilayered system using the layer permeability and skin values estimated by history matching spatial and temporal temperature and/or pressure data sets along the completion interval. Such data may be acquired by wireline formation testing, production-logging-tool (PLT), or distributed temperature sensing (DTS) fiber-optic cables. We use an in-house thermal, transient coupled reservoir/wellbore simulator developed during this study. It solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The effects of the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection are all included for predicting the flow profiles across the wellbore. The results from our in-house simulator are verified with the results from a commercial simulator for the single-phase fluid flow of a vertical well producing geothermal brine and oil in a two-zone multilayer system. We also compare the results from our rigorous transient coupled wellbore/reservoir model with the results from a model assuming steady-state thermal wellbore model used in the previous studies. We find that the steady-state thermal wellbore model used in the previous studies that ignore accumulation terms in mass, momentum, and thermal energy balances is a reasonably accurate model for predicting wellbore pressures and temperatures when it is coupled with a nonisothermal reservoir model for slightly compressible fluid because the transient effect in the wellbore is less important with the slightly compressible fluid. We investigate the nonlinear parameter estimation problem based on the use of single or multiple observed temperature and/or pressure (if available) profiles recorded spatially inside the wellbore and at the sandface. The purpose is to identify if the wellbore or sandface data profiles are more useful to accurately estimate the permeability and skin information and predict a production-inflow profile of the well depending on the representation of an actual multilayer system by a reduced-layered or fine-layered model. We show that using an upscaled-layered model (e.g., representing each heterogeneous layer with a lumped single layer with uniform permeability and skin) provides estimates that are more toward the thickness-average permeability and skin factors of the layers and may not provide a good prediction of the well’s production-inflow profile. We show that including the sandface temperature data in regression worsens, while the use of wellbore temperature data sets improves the quality of parameter estimation if an upscaled multilayered model is used. We also show that regressing on multiple temperature profiles, preferably at the sandface, alone could be used to predict the production-inflow profile accurately if a “fine” multilayered heterogeneous ","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140405155","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Organophosphonates are commonly used retarders to prolong the thickening time of oilwell cement slurry at medium and high temperatures. In this paper, the impact of calcium sulfate in cement on the retarding effect of ethylene diamine tetra(methylene phosphonic acid) sodium (EDTMPS) was explored. First, the thickening properties of cements from four different factories were studied in detail with varying additions of EDTMPS. The study revealed diverse thickening phenomena, including retarding, accelerating, and increasing the initial consistency of cement slurries. The heat flow of cement hydration was detected, and the mineral changes of cement slurries at the early stage (1–3 hours) were analyzed. Additionally, the effect of EDTMPS on the hydration of tricalcium aluminate (C3A) and gypsum (GP)/bassanite (BS) slurry was investigated through X-ray diffraction (XRD) and ion concentration test. Finally, two clinkers from the same cement factory were mixed with GP/BS of different dosages to study the effect of calcium sulfate type on the thickening properties of cement slurry with EDTMPS. The results revealed that EDTMPS slowed down the dissolution of GP while promoting the dissolution of C3A. The rapid hydration of C3A increased the consistency of cement slurry without the retarding effect of GP. However, EDTMPS promoted the dissolution of BS, which can retard the hydration of C3A. Therefore, EDTMPS is appropriate for cements containing BS.
有机膦酸盐是常用的缓凝剂，可延长油井水泥浆在中高温下的稠化时间。本文探讨了水泥中硫酸钙对乙二胺四甲苯膦酸钠（EDTMPS）缓凝效果的影响。首先，详细研究了四家不同工厂生产的不同 EDTMPS 添加量水泥的增稠性能。研究发现了多种增稠现象，包括延缓、加速和增加水泥浆的初始稠度。对水泥水化热流进行了检测，并分析了水泥浆早期（1-3 小时）的矿物变化。此外，还通过 X 射线衍射（XRD）和离子浓度测试研究了 EDTMPS 对铝酸三钙（C3A）和石膏（GP）/重晶石（BS）浆体水化的影响。最后，将来自同一水泥厂的两种熟料与不同掺量的 GP/BS 混合，研究硫酸钙类型对 EDTMPS 水泥浆稠化性能的影响。结果显示，EDTMPS 减慢了 GP 的溶解速度，同时促进了 C3A 的溶解。C3A 的快速水化增加了水泥浆的稠度，而 GP 却没有起到延缓作用。然而，EDTMPS 促进了 BS 的溶解，而 BS 会延缓 C3A 的水化。因此，EDTMPS 适用于含有 BS 的水泥。
{"title":"The Effect of Gypsum/Bassanite on the Retardation of Ethylene Diamine Tetra(Methylene Phosphonic Acid) Sodium in Oil Well Cement Slurry","authors":"Jiamen Huang, Chunyu Wang, Xiao Yao, Chenzi Geng, Yiwei Zou, Yixin Wang","doi":"10.2118/219728-pa","DOIUrl":"https://doi.org/10.2118/219728-pa","url":null,"abstract":"\u0000 Organophosphonates are commonly used retarders to prolong the thickening time of oilwell cement slurry at medium and high temperatures. In this paper, the impact of calcium sulfate in cement on the retarding effect of ethylene diamine tetra(methylene phosphonic acid) sodium (EDTMPS) was explored. First, the thickening properties of cements from four different factories were studied in detail with varying additions of EDTMPS. The study revealed diverse thickening phenomena, including retarding, accelerating, and increasing the initial consistency of cement slurries. The heat flow of cement hydration was detected, and the mineral changes of cement slurries at the early stage (1–3 hours) were analyzed. Additionally, the effect of EDTMPS on the hydration of tricalcium aluminate (C3A) and gypsum (GP)/bassanite (BS) slurry was investigated through X-ray diffraction (XRD) and ion concentration test. Finally, two clinkers from the same cement factory were mixed with GP/BS of different dosages to study the effect of calcium sulfate type on the thickening properties of cement slurry with EDTMPS. The results revealed that EDTMPS slowed down the dissolution of GP while promoting the dissolution of C3A. The rapid hydration of C3A increased the consistency of cement slurry without the retarding effect of GP. However, EDTMPS promoted the dissolution of BS, which can retard the hydration of C3A. Therefore, EDTMPS is appropriate for cements containing BS.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140273238","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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