Replicating downhole conditions using real-time software helps reduce nonproductive time. Hydraulic outputs trend against sensor outputs, enabling event detection. Using real-time fluid properties with fluid tracking hydraulic software helps improve predictions for comparison, enabling faster and more reliable detection of downhole conditions. Two instances of real-time hydraulics simulators capable of tracking property changes of fluid and the positions of discrete fluid volumes within the wellbore were used. One simulator was used with a real-time fluid properties apparatus that provided full six-speed rheology and fluid density in real time. The second simulator used fluid updates provided by the mud engineer on location. The calculated equivalent circulating density (ECD) and predicted standpipe pressure (SPP) from the hydraulics software was compared to actual pressure while drilling (PWD) and measured SPP sensor outputs. The real-time fluid apparatus provided real-time rheology and density values consistently while drilling the section, and data was provided directly to the hydraulics simulator. Comparing ECD predictions with and without the real-time fluid properties made it possible to identify any improvements achieved using such equipment. Although both sets of data showed that the hydraulics simulator was highly accurate, using real-time fluid inputs enabled ECD predictions to trend considerably closer to the PWD measurements. The capability of tracking the predicted ECD against actual sensor outputs enables users to quickly determine deviations in sensor outputs associated with downhole conditions and to observe deviations occurring as a result of inconsistencies within the fluid system. Data presented in this paper are taken from some of the first global deployments of real-time fluid properties measurement equipment used in conjunction with real-time hydraulics software.
{"title":"Enhanced Hydraulic Modeling and Event Detection Using Real-Time Fluid Properties and Fluid Position Tracking Software","authors":"Aidan Porter, Vivek Lie, J. S. Gollapalli","doi":"10.2118/194812-MS","DOIUrl":"https://doi.org/10.2118/194812-MS","url":null,"abstract":"\u0000 Replicating downhole conditions using real-time software helps reduce nonproductive time. Hydraulic outputs trend against sensor outputs, enabling event detection. Using real-time fluid properties with fluid tracking hydraulic software helps improve predictions for comparison, enabling faster and more reliable detection of downhole conditions.\u0000 Two instances of real-time hydraulics simulators capable of tracking property changes of fluid and the positions of discrete fluid volumes within the wellbore were used. One simulator was used with a real-time fluid properties apparatus that provided full six-speed rheology and fluid density in real time. The second simulator used fluid updates provided by the mud engineer on location. The calculated equivalent circulating density (ECD) and predicted standpipe pressure (SPP) from the hydraulics software was compared to actual pressure while drilling (PWD) and measured SPP sensor outputs.\u0000 The real-time fluid apparatus provided real-time rheology and density values consistently while drilling the section, and data was provided directly to the hydraulics simulator. Comparing ECD predictions with and without the real-time fluid properties made it possible to identify any improvements achieved using such equipment. Although both sets of data showed that the hydraulics simulator was highly accurate, using real-time fluid inputs enabled ECD predictions to trend considerably closer to the PWD measurements. The capability of tracking the predicted ECD against actual sensor outputs enables users to quickly determine deviations in sensor outputs associated with downhole conditions and to observe deviations occurring as a result of inconsistencies within the fluid system.\u0000 Data presented in this paper are taken from some of the first global deployments of real-time fluid properties measurement equipment used in conjunction with real-time hydraulics software.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"231 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74473969","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}
Considering the important role that perforation laboratory testing can play in establishing field completion strategies, and thus ultimately well performance, efforts are currently underway to further strengthen the link between laboratory results and field well performance predictions. Some of these efforts focus on integrating advanced diagnostic and computational tools (namely computed tomography (CT), and pore-scale flow simulation) into the perforation testing workflow. This integration enables local variations in permeability and porosity to be identified and quantified, thus improving the interpretation of perforation laboratory results, and ultimately the translation of these results to the downhole environment. CT techniques have been used for core analysis, characterization, and flow visualization since the early 1980s. By the early 1990s, these techniques were being applied to the investigation of laboratory-perforated cores to enhance the interpretation of tests conducted following API RP19B Section 2 or 4. This application has increased dramatically since 2012, following the installation of a CT scanning system on-site at a perforating laboratory facility. As a result, this non-destructive technique has become a preferred method to routinely characterize perforation tunnels and the surrounding rock, as well as to enable the repeated inspection of a perforated core at multiple steps throughout a test sequence designed to mimic field operations scenarios. Coinciding with this development has been the advancement and application of micro-CT technology to better understand pore-scale phenomena, both near and away from the perforation. This paper introduces an integrated test program currently underway and summarizes key results from two experiments in which stressed rock targets were perforated under significantly different conditions. The first experiment involved perforating a moderate strength sandstone core under conditions that retained substantially all perforation damage, thus preserving the "crushed zone". Micro-CT analysis of different locations within the crushed zone region revealed significant compaction, with porosity reductions ranging from 10 to 50% below that of the native rock. Permeability at one of these selected locations was determined and found to be reduced by approximately 35% below the native rock value. The second experiment involved perforating a very high-strength sandstone core under conditions intended to produce full cleanup. CT and micro-CT analysis revealed fine fractures near the tunnel tip and confirmed the near-complete removal of the perforation damage, with only a very thin (less than 1 mm) compacted zone remaining at the tunnel wall. Although this region is interpreted to have very low permeability (as indicated by the near-zero connected porosity detectable at the resolution investigated), a fracture network combined with the shell’s minimal thickness suggests that this would provide a minimal
{"title":"Perforation Damage, Cleanup, and Inflow Performance: Advances in Diagnostics and Characterization","authors":"B. Grove, A. Grader, N. Derzhi, J. McGregor","doi":"10.2118/195019-MS","DOIUrl":"https://doi.org/10.2118/195019-MS","url":null,"abstract":"\u0000 Considering the important role that perforation laboratory testing can play in establishing field completion strategies, and thus ultimately well performance, efforts are currently underway to further strengthen the link between laboratory results and field well performance predictions. Some of these efforts focus on integrating advanced diagnostic and computational tools (namely computed tomography (CT), and pore-scale flow simulation) into the perforation testing workflow. This integration enables local variations in permeability and porosity to be identified and quantified, thus improving the interpretation of perforation laboratory results, and ultimately the translation of these results to the downhole environment.\u0000 CT techniques have been used for core analysis, characterization, and flow visualization since the early 1980s. By the early 1990s, these techniques were being applied to the investigation of laboratory-perforated cores to enhance the interpretation of tests conducted following API RP19B Section 2 or 4. This application has increased dramatically since 2012, following the installation of a CT scanning system on-site at a perforating laboratory facility. As a result, this non-destructive technique has become a preferred method to routinely characterize perforation tunnels and the surrounding rock, as well as to enable the repeated inspection of a perforated core at multiple steps throughout a test sequence designed to mimic field operations scenarios. Coinciding with this development has been the advancement and application of micro-CT technology to better understand pore-scale phenomena, both near and away from the perforation.\u0000 This paper introduces an integrated test program currently underway and summarizes key results from two experiments in which stressed rock targets were perforated under significantly different conditions. The first experiment involved perforating a moderate strength sandstone core under conditions that retained substantially all perforation damage, thus preserving the \"crushed zone\". Micro-CT analysis of different locations within the crushed zone region revealed significant compaction, with porosity reductions ranging from 10 to 50% below that of the native rock. Permeability at one of these selected locations was determined and found to be reduced by approximately 35% below the native rock value. The second experiment involved perforating a very high-strength sandstone core under conditions intended to produce full cleanup. CT and micro-CT analysis revealed fine fractures near the tunnel tip and confirmed the near-complete removal of the perforation damage, with only a very thin (less than 1 mm) compacted zone remaining at the tunnel wall. Although this region is interpreted to have very low permeability (as indicated by the near-zero connected porosity detectable at the resolution investigated), a fracture network combined with the shell’s minimal thickness suggests that this would provide a minimal ","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"92 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75005611","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}
Gregory Jackson, Ghada Almoulani, Y. A. Ansari, Jorge Viamontes
Bahrain has begun exploring unconventional resources in the Khalij Al-Bahrain Basin for the Tuwaiq Mountain Formation. This work is a case study presenting the workflow for characterizing and modeling the unconventional development in Bahrain all the way from petrophysics through geology, completion modeling, and dynamic simulation. The work scope consisted of petrophysical modeling 10 key wells including calibration to core data. The petrophysics showed that the lower Tuwaiq Mountain interval with its TOC signature is remarkably consistent across all of Bahrain. The wells modeled in a 3D geological model with reservoir properties distributed throughout the reservoir to confirm resource in-place estimates published in early 2018. Well stimulation treatment on Well 1 was modeled and tied to the production test. A dynamic model was subsequently built to history match the production test. While not unique in its production match, this calibration is an important step for future optimizations in lieu of microseismic data. All of this information was used to form the basis for optimal completions to refine the next appraisal wells with forecasted production rates. The Tuwaiq Mountain reservoir has commercial potential in Bahrain, particularly in the western area where producibility has been proven. Producibility in the East has not been established as no production tests are available. In addition, future appraisal well locations were identified using the 3D geological model. The best trajectory was chosen such that the wells are estimated to yield EURs more than 500,000 bbls. The results of this project are important for Bahrain as it highlights the unconventional resource and production potential in the country. For the industry, unconventional development is in its early stages outside of North America and Bahrain’s case study can be utilized to expedite the learning curve in many other basins.
{"title":"Modeling of Unconventional Reservoirs: A Case Study from Bahrain’s Khalij Al-Bahrain Basin","authors":"Gregory Jackson, Ghada Almoulani, Y. A. Ansari, Jorge Viamontes","doi":"10.2118/195109-MS","DOIUrl":"https://doi.org/10.2118/195109-MS","url":null,"abstract":"\u0000 Bahrain has begun exploring unconventional resources in the Khalij Al-Bahrain Basin for the Tuwaiq Mountain Formation. This work is a case study presenting the workflow for characterizing and modeling the unconventional development in Bahrain all the way from petrophysics through geology, completion modeling, and dynamic simulation.\u0000 The work scope consisted of petrophysical modeling 10 key wells including calibration to core data. The petrophysics showed that the lower Tuwaiq Mountain interval with its TOC signature is remarkably consistent across all of Bahrain. The wells modeled in a 3D geological model with reservoir properties distributed throughout the reservoir to confirm resource in-place estimates published in early 2018. Well stimulation treatment on Well 1 was modeled and tied to the production test. A dynamic model was subsequently built to history match the production test. While not unique in its production match, this calibration is an important step for future optimizations in lieu of microseismic data. All of this information was used to form the basis for optimal completions to refine the next appraisal wells with forecasted production rates.\u0000 The Tuwaiq Mountain reservoir has commercial potential in Bahrain, particularly in the western area where producibility has been proven. Producibility in the East has not been established as no production tests are available. In addition, future appraisal well locations were identified using the 3D geological model. The best trajectory was chosen such that the wells are estimated to yield EURs more than 500,000 bbls.\u0000 The results of this project are important for Bahrain as it highlights the unconventional resource and production potential in the country. For the industry, unconventional development is in its early stages outside of North America and Bahrain’s case study can be utilized to expedite the learning curve in many other basins.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84918096","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. A. Umar, I. Saaid, A. Sulaimon, R. Pilus, N. A. Amer, A. Halilu, B. M. Negash
Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.
{"title":"Characterization of Native Colloids and Study of Emulsions Stabilized by Asphaltene, Wax, Silicates and Calcites Using Optical Analyzer Turbiscan","authors":"A. A. Umar, I. Saaid, A. Sulaimon, R. Pilus, N. A. Amer, A. Halilu, B. M. Negash","doi":"10.2118/195082-MS","DOIUrl":"https://doi.org/10.2118/195082-MS","url":null,"abstract":"\u0000 Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79527990","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}
Wan Muhammad Luqman Sazali, Sahriza Salwani Md Shah, M. Z. Kashim, B. Kantaatmadja, L. Knuefing, B. Young
PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.
{"title":"The Use of Digital Core Analysis in Understanding the Effects of CO2 Aging to Carbonates Samples","authors":"Wan Muhammad Luqman Sazali, Sahriza Salwani Md Shah, M. Z. Kashim, B. Kantaatmadja, L. Knuefing, B. Young","doi":"10.2118/195074-MS","DOIUrl":"https://doi.org/10.2118/195074-MS","url":null,"abstract":"\u0000 PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83780008","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}
Luai Ali Al-Amoudi, Ba Geri, S. Patil, Salem O. Baarimah
Crude oil viscosity is a significant parameter for the fluid flow in both porous media and pipe lines. Therefore, it has to be determined using highly accurate methods. Oil viscosity is usually predicted with the correlations obtained from the laboratory measured data. However, some of the presented correlations have very complicated assumptions which make them very difficult to apply in most of the case studies reported. On the other hand, simplified correlations companies the accuracy. The present work in this paper studies predictive capabilities of Artificial Intelligence (AI) to estimate the oil viscosity. Artificial Neural Network (ANN) models are proposed to predict the undersaturated, saturated and dead oil viscosity in Yemeni fields. A data set consisting 545 of laboratory measurements on oil samples was gathered from different oil fields in Yemen. 70% of the data points were used to train the proposed ANN models while the remaining data set was tested the model performance. The performance of the ANN methods was compared with some of the conventional correlations such as (Beal's correlation, Khan's correlation, Kartoatmodjo and Schmidt correlation, Vasquez-Begg's correlation, Chew and Connaly correlation, Beggs and Robinson correlation, Elsharqawy correlation and Glaso's correlation). The result of this study shows the superiority of the Artificial Neural Network (ANN) models over the current models for predicting oil viscosity from PVT data. The comparative results displayed that the proposed ANN models performed better with higher accuracy than those obtained with published correlations.
{"title":"Development of Artificial Intelligence Models for Prediction of Crude Oil Viscosity","authors":"Luai Ali Al-Amoudi, Ba Geri, S. Patil, Salem O. Baarimah","doi":"10.2118/194741-MS","DOIUrl":"https://doi.org/10.2118/194741-MS","url":null,"abstract":"\u0000 Crude oil viscosity is a significant parameter for the fluid flow in both porous media and pipe lines. Therefore, it has to be determined using highly accurate methods. Oil viscosity is usually predicted with the correlations obtained from the laboratory measured data. However, some of the presented correlations have very complicated assumptions which make them very difficult to apply in most of the case studies reported. On the other hand, simplified correlations companies the accuracy.\u0000 The present work in this paper studies predictive capabilities of Artificial Intelligence (AI) to estimate the oil viscosity. Artificial Neural Network (ANN) models are proposed to predict the undersaturated, saturated and dead oil viscosity in Yemeni fields. A data set consisting 545 of laboratory measurements on oil samples was gathered from different oil fields in Yemen. 70% of the data points were used to train the proposed ANN models while the remaining data set was tested the model performance. The performance of the ANN methods was compared with some of the conventional correlations such as (Beal's correlation, Khan's correlation, Kartoatmodjo and Schmidt correlation, Vasquez-Begg's correlation, Chew and Connaly correlation, Beggs and Robinson correlation, Elsharqawy correlation and Glaso's correlation).\u0000 The result of this study shows the superiority of the Artificial Neural Network (ANN) models over the current models for predicting oil viscosity from PVT data. The comparative results displayed that the proposed ANN models performed better with higher accuracy than those obtained with published correlations.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88555905","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}
In recent decades, the widespread implementation of horizontal drilling and multistage hydraulic fracturing in unconventional plays has increased the use of fresh water in oilfield operations. The formulation of fracturing fluids with non-fresh water sources such as seawater or produced water are attracting more attention due to the long term sustainability of non-fresh water use. Fracturing fluids using seawater are available in the industry. But the compatibility between the composition of local seawater and reservoir brine can add complication in the formation damage consideration. For example, if a seawater rich in sulfate comes in contact with formation brine rich in calcium or barium, severe scale can be expected if the proper caution is not taken. Treated seawater with nano-filtration to removal sulfate is a good practice to eliminate this problem. This paper describes a fracturing fluid formulated by using nanofiltered seawater for high temperature applications at 300 to 325°F. The crosslinked fracturing fluid formulation was optimized in the lab to accommodate the nanofiltered seawater, resulting in satisfactory fluid performance thereby enabling the fracturing operations to conserve fresh water. A high-temperature crosslinked fracturing fluid system was prepared with the nanofiltered local seawater. The fluid system showed robust stability at high temperatures. For example, the fluid viscosity stayed above 400 cP (at 100 sec−1 shear rate) for 2 hr at 300°F, with 45 ppt of the polymer loading. At 325°F, the fluid maintained viscosity above 300 cP for 2 hr with 60 ppt of the polymer loading. The nanofiltered seawater-based fluids was found to be compatible with a number of commonly used fluid additives including biocide, surfactant, and clay stabilizer. The fluid system also showed low formation damage and scaling tendencies. In the coreflow tests at 300°F, a regained permeability of greater than 95% was obtained. In the scaling tests without the presence of scale inhibitor at 300°F, traceable (<0.01 wt %) amount of scale was observed in the mixture of the nanofiltered seawater and high total dissolved solids (TDS) formation brine. Overall, it was found using the nanofiltered seawater can lead to better fluid stability at elevated temperatures, better fluid cleanup, and reduced downhole scaling tendency. By careful selection of the fluid components, the nanofiltered seawater-based fluid relieve the burden of needing fresh water for hydraulic fracturing treatment, allowing for a more sustainable approach. This paper discusses the technical functions of the key fluid additives used in the fracturing fluid preparation.
{"title":"A More Sustainable Approach: Nanofiltered Seawater-Based High-Temperature Fracturing Fluids","authors":"Leiming Li, Fakuen F. Chang, Saini Rajesh Kumar","doi":"10.2118/194708-MS","DOIUrl":"https://doi.org/10.2118/194708-MS","url":null,"abstract":"\u0000 In recent decades, the widespread implementation of horizontal drilling and multistage hydraulic fracturing in unconventional plays has increased the use of fresh water in oilfield operations. The formulation of fracturing fluids with non-fresh water sources such as seawater or produced water are attracting more attention due to the long term sustainability of non-fresh water use.\u0000 Fracturing fluids using seawater are available in the industry. But the compatibility between the composition of local seawater and reservoir brine can add complication in the formation damage consideration. For example, if a seawater rich in sulfate comes in contact with formation brine rich in calcium or barium, severe scale can be expected if the proper caution is not taken. Treated seawater with nano-filtration to removal sulfate is a good practice to eliminate this problem. This paper describes a fracturing fluid formulated by using nanofiltered seawater for high temperature applications at 300 to 325°F. The crosslinked fracturing fluid formulation was optimized in the lab to accommodate the nanofiltered seawater, resulting in satisfactory fluid performance thereby enabling the fracturing operations to conserve fresh water.\u0000 A high-temperature crosslinked fracturing fluid system was prepared with the nanofiltered local seawater. The fluid system showed robust stability at high temperatures. For example, the fluid viscosity stayed above 400 cP (at 100 sec−1 shear rate) for 2 hr at 300°F, with 45 ppt of the polymer loading. At 325°F, the fluid maintained viscosity above 300 cP for 2 hr with 60 ppt of the polymer loading. The nanofiltered seawater-based fluids was found to be compatible with a number of commonly used fluid additives including biocide, surfactant, and clay stabilizer. The fluid system also showed low formation damage and scaling tendencies. In the coreflow tests at 300°F, a regained permeability of greater than 95% was obtained. In the scaling tests without the presence of scale inhibitor at 300°F, traceable (<0.01 wt %) amount of scale was observed in the mixture of the nanofiltered seawater and high total dissolved solids (TDS) formation brine. Overall, it was found using the nanofiltered seawater can lead to better fluid stability at elevated temperatures, better fluid cleanup, and reduced downhole scaling tendency.\u0000 By careful selection of the fluid components, the nanofiltered seawater-based fluid relieve the burden of needing fresh water for hydraulic fracturing treatment, allowing for a more sustainable approach. This paper discusses the technical functions of the key fluid additives used in the fracturing fluid preparation.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83200655","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}
R. Kayumov, R. E. Urbina, K. Bander, G. Aidagulov, Fakuen F. Chang
Tight carbonate reservoirs often require acid fracturing stimulation treatments to exploit them economically. In a horizontal well with a long openhole interval across a tight carbonate reservoir, multiple acid fracturing stages might be desirable, however this typically requires permanent completion devices to isolate discrete target intervals into specific stages. Multistage completions face many complications, such as hole-shape dependence, risk of communication between stages, completion deployment risks, and cost. A simplified completion technique was proposed to enable placement of multiple fractures along the openhole reservoir section without a complex completion. The main challenge in fracturing long openhole horizontal wellbores is limited or lack of control in positioning and orienting initiated fractures. One way to lower the fracturing pressure and force the hydraulic fracture to initiate at one or more desired target depths is to mechanically weaken the formation at specific points along the wellbore. An example of such a weak point is a cavity in the shape of a circular notch cut into the openhole wall. This technique was implemented in a multilateral horizontal water injector well drilled in a tight carbonate reservoir. Four circular notches were cut at predefined depths before stimulation with a goal of creating four separate fractures during one pumping operation. The volume of treating fluids required for the operation was significantly larger compared to a conventional acid fracturing job with only a single fracture propagating. To increase the effectiveness of stimulating all four intervals, degradable particulate diversion material was used during the treatment to temporarily isolate already stimulated fractures and divert treating fluids into less stimulated intervals. The stimulation treatment was successfully placed after the circular notches were created by coiled tubing using a rotational jetting tool with hydrochloric acid. As the primary result of the circular notching and acid fracturing stimulation, the injectivity index of this well increased almost four times. Temperature, caliper, production, and saturation logs were taken before and after fracturing to evaluate the applied completion approach. These measurements confirmed improved overall injectivity and highlighted areas for further improvements to the new technique, mainly related to preventing overstimulation of untargeted laterals in a multilateral well.
{"title":"Efficient Large Volume Acid Fracturing in Openhole Horizontal Well with Pre-Created Circular Notches","authors":"R. Kayumov, R. E. Urbina, K. Bander, G. Aidagulov, Fakuen F. Chang","doi":"10.2118/194779-MS","DOIUrl":"https://doi.org/10.2118/194779-MS","url":null,"abstract":"\u0000 Tight carbonate reservoirs often require acid fracturing stimulation treatments to exploit them economically. In a horizontal well with a long openhole interval across a tight carbonate reservoir, multiple acid fracturing stages might be desirable, however this typically requires permanent completion devices to isolate discrete target intervals into specific stages. Multistage completions face many complications, such as hole-shape dependence, risk of communication between stages, completion deployment risks, and cost. A simplified completion technique was proposed to enable placement of multiple fractures along the openhole reservoir section without a complex completion.\u0000 The main challenge in fracturing long openhole horizontal wellbores is limited or lack of control in positioning and orienting initiated fractures. One way to lower the fracturing pressure and force the hydraulic fracture to initiate at one or more desired target depths is to mechanically weaken the formation at specific points along the wellbore. An example of such a weak point is a cavity in the shape of a circular notch cut into the openhole wall. This technique was implemented in a multilateral horizontal water injector well drilled in a tight carbonate reservoir. Four circular notches were cut at predefined depths before stimulation with a goal of creating four separate fractures during one pumping operation. The volume of treating fluids required for the operation was significantly larger compared to a conventional acid fracturing job with only a single fracture propagating. To increase the effectiveness of stimulating all four intervals, degradable particulate diversion material was used during the treatment to temporarily isolate already stimulated fractures and divert treating fluids into less stimulated intervals.\u0000 The stimulation treatment was successfully placed after the circular notches were created by coiled tubing using a rotational jetting tool with hydrochloric acid. As the primary result of the circular notching and acid fracturing stimulation, the injectivity index of this well increased almost four times. Temperature, caliper, production, and saturation logs were taken before and after fracturing to evaluate the applied completion approach. These measurements confirmed improved overall injectivity and highlighted areas for further improvements to the new technique, mainly related to preventing overstimulation of untargeted laterals in a multilateral well.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88715326","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 salinity and ionic strength of injection water can make favorable impacts on wettability and oil recovery in different carbonate and sandstone reservoirs. The interaction mechanism between dissolved ions in injection water and reservoir fluids is a key ongoing research area. Most of these interactions occur at the thin film interfaces and so are considered one of the challenges in identifying and understanding the mechanisms. Conventional macro and microscopic laboratory techniques are commonly applied to determine contact angles, surface charges, and coreflooding to measure any incremental increase in oil recovery. In this paper, advanced sum frequency generation (SFG) spectroscopy is utilized, for the first time, to characterize the chemical structures of molecules at the brine/crude oil interfaces. The change in the chemical structure is perceived with time at a broad wavenumber range from 1000 to 3900 cm−1. Distinct spectral signatures of oil components and water ions are detected for high salinity water (HSW), modified ionic strength water (MIW), and ions-free solutions. The SFG data is also compared with the previous macroscopic wettability results to predict the components that are highly affected during waterflooding/enhanced oil recovery (EOR) processes. This study brings new insights about understanding the chemical structures at brine/crude oil monolayers and aqueous interfaces. The measured spectra at the interfaces along with the observed signal intensity trends are discussed in terms of composition and structure of organic and inorganic components. For example, SFG results from MIW oil interfaces and has higher spectral intensity at 2860 and 1700 cm−1 wavenumbers when compared with other brines used. These results exactly correlate with the C-H and C=O stretching bonds, which consider the key oil components at the interfaces. The novelty of this interfacial study can give more ability to understand the reaction mechanisms as altering the ionic strength and salinity of the injection water. Such understanding is also crucial in optimizing the chemistry of injection water and its interaction with oil components and carbonate rock to ultimately alter wettability toward water-wet.
{"title":"Novel Characterization of Thin Film at Reservoir Fluids Interfaces in Carbonates","authors":"M. Alotaibi, D. Cha, S. Alsaleh, A. Yousef","doi":"10.2118/194757-MS","DOIUrl":"https://doi.org/10.2118/194757-MS","url":null,"abstract":"\u0000 The salinity and ionic strength of injection water can make favorable impacts on wettability and oil recovery in different carbonate and sandstone reservoirs. The interaction mechanism between dissolved ions in injection water and reservoir fluids is a key ongoing research area. Most of these interactions occur at the thin film interfaces and so are considered one of the challenges in identifying and understanding the mechanisms. Conventional macro and microscopic laboratory techniques are commonly applied to determine contact angles, surface charges, and coreflooding to measure any incremental increase in oil recovery.\u0000 In this paper, advanced sum frequency generation (SFG) spectroscopy is utilized, for the first time, to characterize the chemical structures of molecules at the brine/crude oil interfaces. The change in the chemical structure is perceived with time at a broad wavenumber range from 1000 to 3900 cm−1. Distinct spectral signatures of oil components and water ions are detected for high salinity water (HSW), modified ionic strength water (MIW), and ions-free solutions.\u0000 The SFG data is also compared with the previous macroscopic wettability results to predict the components that are highly affected during waterflooding/enhanced oil recovery (EOR) processes. This study brings new insights about understanding the chemical structures at brine/crude oil monolayers and aqueous interfaces. The measured spectra at the interfaces along with the observed signal intensity trends are discussed in terms of composition and structure of organic and inorganic components. For example, SFG results from MIW oil interfaces and has higher spectral intensity at 2860 and 1700 cm−1 wavenumbers when compared with other brines used. These results exactly correlate with the C-H and C=O stretching bonds, which consider the key oil components at the interfaces.\u0000 The novelty of this interfacial study can give more ability to understand the reaction mechanisms as altering the ionic strength and salinity of the injection water. Such understanding is also crucial in optimizing the chemistry of injection water and its interaction with oil components and carbonate rock to ultimately alter wettability toward water-wet.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84537396","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}
Pub Date : 2019-03-12DOI: 10.36548/jsws.2019.1.003
K. Raj, S. S. Dr
With the ever increasing research in communication technology, smart systems and gadgets are emerging at a very fast pace. A recent trend is the research in internet of things (IoT) which facilitates access of information and services at any point of time around the globe thus elevating the process of digitization to a new era. Multi homing is a concept which facilitates connection of a user over multiple networks. These networks may be heterogeneous or homogeneous. This concept of multihoming acts as a strong backbone to wireless sensor networks where routing of information over the links and channels is quite a critical process. The routing of information from source to destination defines the overall accuracy of the entire wireless network. This efficiency largely dictated by an efficient routing process is influenced by many factors which include node efficiency, node lifetime, and the characteristics of the link between the nodes.
{"title":"IOT BASED MULTI-HOMING APPLICATIONS - A REVIEW","authors":"K. Raj, S. S. Dr","doi":"10.36548/jsws.2019.1.003","DOIUrl":"https://doi.org/10.36548/jsws.2019.1.003","url":null,"abstract":"With the ever increasing research in communication technology, smart systems and gadgets are emerging at a very fast pace. A recent trend is the research in internet of things (IoT) which facilitates access of information and services at any point of time around the globe thus elevating the process of digitization to a new era. Multi homing is a concept which facilitates connection of a user over multiple networks. These networks may be heterogeneous or homogeneous. This concept of multihoming acts as a strong backbone to wireless sensor networks where routing of information over the links and channels is quite a critical process. The routing of information from source to destination defines the overall accuracy of the entire wireless network. This efficiency largely dictated by an efficient routing process is influenced by many factors which include node efficiency, node lifetime, and the characteristics of the link between the nodes.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87950016","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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