M. Enzien, Sadie Starustka, Michael J Gurecki, Trinity Fincher-Miller, Bryce Kuhn, Carly Sowecke, Kody B Jones, Kevin O'Sullivan, Keith C. Norris, J. Stidham
Inconsistent bacterial control and monitoring led to variability in Salt Water Disposal (SWD) well performance and injectivity creating excess costs in biocide applications and remedial work. A metagenomics study using Whole Genome Sequencing (WGS) was conducted to determine the source(s) of problematic microorganisms throughout the process life cycle: Freshwater> Drilling> Completion> Flowback> Produced water> SWD. A total of 30 metagenomes were collected from the 6 process stages and identification and quantification of the major microbial taxa from each of these stages were identified. "Taxonomy to Function" associations were identified for all the major taxa found in the SWD fluids. WGS was performed on positive Sulfate Reducing Bacteria (SRB) and Acid Producing Bacteria (APB) media bottles inoculated in the field for a Flowback sample. Four of the six major taxa found in SWD samples are considered groups of microorganisms known to cause microbiologically influenced corrosion (MIC): Clostridia, methanogens, SRB and Iron Reducing bacteria. Thermovirga and Thermotagae, were the two most abundant taxa found in SWD samples, both thermophilic halophilic fermenting bacteria. The Fe reducing bacteria Shewanella was only detected in Drilling and SWD fluids suggesting its source was Drilling fluids. Completion fluid metagenome profiles from two separate sites followed similar patterns. During middle of completions Proteobacteria phyla were dominant taxa represented mostly by Pseudomonas. Other abundant phyla were all characteristic of polymer degrading bacteria. None of these taxa were dominant populations identified in SWD waters. Fresh water only shared similar taxa with Drilling and Completion fluids. A few minor taxa from Drilling and Completion stages show up as significant taxa in SWD fluids. The majority of taxa found in SWD samples appear to originate from Flowback and Produced waters, although at lower abundances than found in SWD samples. It cannot be determined if the microorganisms found in Flowback and Produced waters were endemic to the formation or come from contaminated source waters, i.e. process equipment used to store and transport water sources. Petrotoga mobilis was the dominant population of bacteria that grew in both media bottles, 96% and 77% for SRB and APB, respectively, while Petrotoga was detected at 14% in the field sample. The most abundant bacteria detected in field sample were Clostridia (38%) while only 2.7% were detected in APB media. SRB media bottle had 0.18% SRB detected by WGS; APB media had 9% SRB population abundance. No SRB were detected in corresponding field sample or below detectable limits (BDL) for WGS methods (<0.01%). WGS was forensically used to successfully identify type and source of problematic microorganism in SWD facilities. Results from media bottle and field sample comparisons stress the importance of developing improved field monitoring techniques that more accurately detect the dominant m
{"title":"Metagenomics Microbial Characterization of Production and Process Fluids in the Powder River Basin: Identification and Sources of Problematic Microorganisms Associated with SWD Facilities","authors":"M. Enzien, Sadie Starustka, Michael J Gurecki, Trinity Fincher-Miller, Bryce Kuhn, Carly Sowecke, Kody B Jones, Kevin O'Sullivan, Keith C. Norris, J. Stidham","doi":"10.2118/204335-ms","DOIUrl":"https://doi.org/10.2118/204335-ms","url":null,"abstract":"\u0000 Inconsistent bacterial control and monitoring led to variability in Salt Water Disposal (SWD) well performance and injectivity creating excess costs in biocide applications and remedial work. A metagenomics study using Whole Genome Sequencing (WGS) was conducted to determine the source(s) of problematic microorganisms throughout the process life cycle: Freshwater> Drilling> Completion> Flowback> Produced water> SWD.\u0000 A total of 30 metagenomes were collected from the 6 process stages and identification and quantification of the major microbial taxa from each of these stages were identified. \"Taxonomy to Function\" associations were identified for all the major taxa found in the SWD fluids. WGS was performed on positive Sulfate Reducing Bacteria (SRB) and Acid Producing Bacteria (APB) media bottles inoculated in the field for a Flowback sample.\u0000 Four of the six major taxa found in SWD samples are considered groups of microorganisms known to cause microbiologically influenced corrosion (MIC): Clostridia, methanogens, SRB and Iron Reducing bacteria. Thermovirga and Thermotagae, were the two most abundant taxa found in SWD samples, both thermophilic halophilic fermenting bacteria. The Fe reducing bacteria Shewanella was only detected in Drilling and SWD fluids suggesting its source was Drilling fluids. Completion fluid metagenome profiles from two separate sites followed similar patterns. During middle of completions Proteobacteria phyla were dominant taxa represented mostly by Pseudomonas. Other abundant phyla were all characteristic of polymer degrading bacteria. None of these taxa were dominant populations identified in SWD waters. Fresh water only shared similar taxa with Drilling and Completion fluids. A few minor taxa from Drilling and Completion stages show up as significant taxa in SWD fluids. The majority of taxa found in SWD samples appear to originate from Flowback and Produced waters, although at lower abundances than found in SWD samples. It cannot be determined if the microorganisms found in Flowback and Produced waters were endemic to the formation or come from contaminated source waters, i.e. process equipment used to store and transport water sources.\u0000 Petrotoga mobilis was the dominant population of bacteria that grew in both media bottles, 96% and 77% for SRB and APB, respectively, while Petrotoga was detected at 14% in the field sample. The most abundant bacteria detected in field sample were Clostridia (38%) while only 2.7% were detected in APB media. SRB media bottle had 0.18% SRB detected by WGS; APB media had 9% SRB population abundance. No SRB were detected in corresponding field sample or below detectable limits (BDL) for WGS methods (<0.01%).\u0000 WGS was forensically used to successfully identify type and source of problematic microorganism in SWD facilities. Results from media bottle and field sample comparisons stress the importance of developing improved field monitoring techniques that more accurately detect the dominant m","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73096346","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}
Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.
{"title":"How Does EOR Polymer Impact Scale Control During ASP Flooding?","authors":"Ya Liu, Rebecca Vilain, D. Shen","doi":"10.2118/204350-ms","DOIUrl":"https://doi.org/10.2118/204350-ms","url":null,"abstract":"\u0000 Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"127 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80057250","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}
Surface roughness of rocks had a significant influence on surfactant adsorption in enhanced oil recovery (EOR), both in terms of the total amount adsorbed as well as of the kinetics of adsorption. Combining electrochemical techniques and quartz crystal microbalance with dissipation monitoring (QCM) into one analysis setup opens up new avenues for depositing model rock surfaces and investigating the adsorption behavior. Using electrochemically assisted deposition, uniform and well-covered metal-CaCO3 sensors were obtained to simulate rough carbonate rocks and characterized by scanning electron microscope with energy dispersive X-ray analysis (SEM-EDX). The deposition process was controlled by the nitrate and oxygen electroreduction reactions in the presence of bicarbonate and calcium ions. The deposited mass of CaCO3 was calculated and the coverages for Au-CaCO3 and Pt-CaCO3 sensors were between 20 - 60%. It is observed that mostly cubic-like CaCO3 crystals were formed with crystal sizes around 20 to 50 µm from the SEM micrographs. The bigger crystals were surrounded by bare regions of Pt surface, suggesting the existence of Ostwald ripening process. Prior to the investigation of the deposited CaCO3 surfaces, the adsorption of anionic surfactant alcohol alkoxy sulfate (AAS) was studied on a smooth commercial CaCO3 surface with varying pH and CaCl2concentrations using QCM. Subsequently, surfactant adsorption was performed on the rough deposited CaCO3 surfaces and their adsorption behavior were compared. On a smooth CaCO3 surface, a fast adsorption of AAS surfactant was observed, whereas the desorption process was characterized as a two-step process. Compared to the smooth CaCO3surface, an increase of the frequency shift of about 5 times was observed on the deposited CaCO3 surfaces. This observation was mainly ascribed to the rougher surfaces, having more adsorption sites for AAS binding, and also the liquid trapping effect, resulting in more frequency shifts. It is suggested that a rough model mineral surface could be a better representation of a rock surface, presenting the implications of the new understanding for surfactant adsorption on different rock surfaces in EOR.
{"title":"Electrochemically Assisted Deposition of Calcium Carbonate Surfaces for Anionic Surfactant Adsorption: Implications for Enhanced Oil Recovery","authors":"Zilong Liu, Hayati Onay, Fengzhi Guo, Pegah Hedayati","doi":"10.2118/204283-ms","DOIUrl":"https://doi.org/10.2118/204283-ms","url":null,"abstract":"\u0000 Surface roughness of rocks had a significant influence on surfactant adsorption in enhanced oil recovery (EOR), both in terms of the total amount adsorbed as well as of the kinetics of adsorption. Combining electrochemical techniques and quartz crystal microbalance with dissipation monitoring (QCM) into one analysis setup opens up new avenues for depositing model rock surfaces and investigating the adsorption behavior. Using electrochemically assisted deposition, uniform and well-covered metal-CaCO3 sensors were obtained to simulate rough carbonate rocks and characterized by scanning electron microscope with energy dispersive X-ray analysis (SEM-EDX). The deposition process was controlled by the nitrate and oxygen electroreduction reactions in the presence of bicarbonate and calcium ions. The deposited mass of CaCO3 was calculated and the coverages for Au-CaCO3 and Pt-CaCO3 sensors were between 20 - 60%. It is observed that mostly cubic-like CaCO3 crystals were formed with crystal sizes around 20 to 50 µm from the SEM micrographs. The bigger crystals were surrounded by bare regions of Pt surface, suggesting the existence of Ostwald ripening process.\u0000 Prior to the investigation of the deposited CaCO3 surfaces, the adsorption of anionic surfactant alcohol alkoxy sulfate (AAS) was studied on a smooth commercial CaCO3 surface with varying pH and CaCl2concentrations using QCM. Subsequently, surfactant adsorption was performed on the rough deposited CaCO3 surfaces and their adsorption behavior were compared. On a smooth CaCO3 surface, a fast adsorption of AAS surfactant was observed, whereas the desorption process was characterized as a two-step process. Compared to the smooth CaCO3surface, an increase of the frequency shift of about 5 times was observed on the deposited CaCO3 surfaces. This observation was mainly ascribed to the rougher surfaces, having more adsorption sites for AAS binding, and also the liquid trapping effect, resulting in more frequency shifts. It is suggested that a rough model mineral surface could be a better representation of a rock surface, presenting the implications of the new understanding for surfactant adsorption on different rock surfaces in EOR.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73570565","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 formation of calcium carbonate scale within produced brine as it passes through topside heaters is a very common flow assurance challenge. Normally this scale risk is predicted and chemically controlled via scale inhibitors deployed upstream of the point of brine supersaturation. In some operations chemical application is not fully effective due to under treating of the chemical or carbonate from the reservoir (fines) builds up within the heaters. In cases of reduced fluid throughput cleaning of the inorganic scale is required. The most common method of cleaning is to take the heater offline and batch clean with acids (mineral or organic) to remove the deposits. This paper outlines an investigation into the performance of conventional batch cleaning vs a more novel application method of online cleaning the heater while operating with application of organic acid into the produced fluid upstream of the heaters. The online cleaning process was evaluated via laboratory tests where packed column of field scale were flushed with organic acid within the produced water, and for comparison mineral acid, to understand the potential for online cleaning vs batch cleaning and what factors influenced the effectiveness of these application methods. Factors evaluated included flow rate/contact time, acid strength and acid type. During these online cleaning tests, the effluent of each column was evaluated for pH and finally weight loss at the end of the tests. The online cleaning results were compared to conventional batch cleaning assessment of the same scale samples via static bottle tests The observations from the tests show that online cleaning using both organic and mineral acids result in the development of preferential flow paths within the scale packed columns that reduces the effectiveness of the cleaning chemicals. Improvements to the cleaning program were investigated such as the scale thickness when cleaning is first started to improve cleaning performance and fluid flow rate, increased acid concentration and liquid to solid ratio changes. Field application data from the initial cleaning programs and improvements to the cleaning programs will be shared as part of this publication The factors that need to be assessed to determine if this method is suitable for a specific process system and likelihood of effective scale removal are presented. This method does present the possibility for some production systems that cleaning of carbonate scale can be carried out without the need to take the heater offline for chemical batch or mechanical cleaning.
{"title":"Online Cleaning of Carbonate Deposits. The Potential and Limitations of a Novel Cleaning Method","authors":"M. Jordan, L. Sutherland, C. Johnston","doi":"10.2118/204365-ms","DOIUrl":"https://doi.org/10.2118/204365-ms","url":null,"abstract":"\u0000 The formation of calcium carbonate scale within produced brine as it passes through topside heaters is a very common flow assurance challenge. Normally this scale risk is predicted and chemically controlled via scale inhibitors deployed upstream of the point of brine supersaturation. In some operations chemical application is not fully effective due to under treating of the chemical or carbonate from the reservoir (fines) builds up within the heaters. In cases of reduced fluid throughput cleaning of the inorganic scale is required. The most common method of cleaning is to take the heater offline and batch clean with acids (mineral or organic) to remove the deposits.\u0000 This paper outlines an investigation into the performance of conventional batch cleaning vs a more novel application method of online cleaning the heater while operating with application of organic acid into the produced fluid upstream of the heaters. The online cleaning process was evaluated via laboratory tests where packed column of field scale were flushed with organic acid within the produced water, and for comparison mineral acid, to understand the potential for online cleaning vs batch cleaning and what factors influenced the effectiveness of these application methods. Factors evaluated included flow rate/contact time, acid strength and acid type. During these online cleaning tests, the effluent of each column was evaluated for pH and finally weight loss at the end of the tests. The online cleaning results were compared to conventional batch cleaning assessment of the same scale samples via static bottle tests\u0000 The observations from the tests show that online cleaning using both organic and mineral acids result in the development of preferential flow paths within the scale packed columns that reduces the effectiveness of the cleaning chemicals. Improvements to the cleaning program were investigated such as the scale thickness when cleaning is first started to improve cleaning performance and fluid flow rate, increased acid concentration and liquid to solid ratio changes. Field application data from the initial cleaning programs and improvements to the cleaning programs will be shared as part of this publication\u0000 The factors that need to be assessed to determine if this method is suitable for a specific process system and likelihood of effective scale removal are presented. This method does present the possibility for some production systems that cleaning of carbonate scale can be carried out without the need to take the heater offline for chemical batch or mechanical cleaning.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83112337","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 oil well cement placed in the annulus between casings and the formations experience high stresses under downhole conditions. These frequent stresses deteriorate the mechanical properties of cement and lead to the formation of micro-cracks and fractures, which affect production and increases the cost of operation. Although several polymeric materials have been employed to improve tensile properties of the cement, these additives have also adversely affected the compressive strength of the cement. A highly stable polymeric additive, triazine-based polymers, is designed, synthesized, and compounded with the cement to improve the tensile properties of the well-cement. Triazine polymer was characterized by fourier transform infrared spectroscopy and thermogravimetric analysis. The triazine polymer was mixed with cement and the cement slurries were cured at 180 °F under 3000 psi for 3 days. The set-cement samples were subjected to mechanical testing under high temperature and high pressure to study the elastic properties of the cement. The introduction of this polymer into the cement has improved the elastic properties of the cement with minimum reduction in compressive strength. The thickening time, dynamic compressive strength development, rheology, fluid loss properties, and brazilian tensile strength of the control and cement with triazine polymers were studied to understand the effect of this newly developed polymeric additive. The molecular interaction of the triazine polymer with cement particles has shown formation of covalent linkage between the polymer and cement particle. We have observed a 15 % decrease in Young's modulus for cement compounded with 2%wt. of triazine polymer, indicating the introduction of elastic properties in wellbore cement.
{"title":"Triazine Polymers for Improving Elastic Properties in Oil Well Cements","authors":"Hasmukh R. Patel, Kenneth W. Johnson, R. Martinez","doi":"10.2118/204333-ms","DOIUrl":"https://doi.org/10.2118/204333-ms","url":null,"abstract":"\u0000 The oil well cement placed in the annulus between casings and the formations experience high stresses under downhole conditions. These frequent stresses deteriorate the mechanical properties of cement and lead to the formation of micro-cracks and fractures, which affect production and increases the cost of operation. Although several polymeric materials have been employed to improve tensile properties of the cement, these additives have also adversely affected the compressive strength of the cement. A highly stable polymeric additive, triazine-based polymers, is designed, synthesized, and compounded with the cement to improve the tensile properties of the well-cement. Triazine polymer was characterized by fourier transform infrared spectroscopy and thermogravimetric analysis. The triazine polymer was mixed with cement and the cement slurries were cured at 180 °F under 3000 psi for 3 days. The set-cement samples were subjected to mechanical testing under high temperature and high pressure to study the elastic properties of the cement. The introduction of this polymer into the cement has improved the elastic properties of the cement with minimum reduction in compressive strength. The thickening time, dynamic compressive strength development, rheology, fluid loss properties, and brazilian tensile strength of the control and cement with triazine polymers were studied to understand the effect of this newly developed polymeric additive. The molecular interaction of the triazine polymer with cement particles has shown formation of covalent linkage between the polymer and cement particle. We have observed a 15 % decrease in Young's modulus for cement compounded with 2%wt. of triazine polymer, indicating the introduction of elastic properties in wellbore cement.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"101 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80734681","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}
Alhad Phatak, B. Seymour, Ginger Ren, Isaias Gonzalez
High Viscosity Friction Reducers (HVFRs) are often employed in hydraulic fracturing fluids to increase the proppant carrying capacity of slickwater fluids. However, it has been widely reported that the performance of HVFR fluids drops precipitously with even small amounts of salt. This study explores and reports the use of surfactants to alleviate the loss of performance of HVFR fluids due to salinity in the mix water. Fracturing fluids were prepared in the laboratory by mixing the HVFR at concentrations between 2 and 8 gal/1,000 gal with and without surfactant formulations. The viscosities of the fluids were measured on a TA Instruments DHR-3 rheometer using a concentric cylinder geometry. Both anionic and cationic HVFRs were tested with various surfactants. As expected, we observed that HVFR fluids display dramatic loss of viscosity with the addition of as little as 1% salt to the mix water. However, certain surfactant formulations were found to provide a significant boost in viscosity of HVFR fluids in brines over a wide range of shear rates. Increases in viscosity by a factor of as much as 10 times were observed, particularly at low shear rates. The ability of the surfactant formulations to enhance fluid viscosity was observed in both monovalent and divalent model brines, as well as brines that mimicked field produced water compositions. In addition, measurements were also performed in a slot flow device to determine if the results from the rheometer translated to proppant transport characteristics of the fluids. The slot flow results were found to correlate well with fluid viscosity measurements. The fluids containing the surfactant formulation transported nearly 4 times as much proppant as fluids not containing surfactant through a 2.5 ft. long rectangular slot of 0.5 in. thickness at a proppant concentration of 2 lb/gal. An obvious benefit of the approach proposed in this study is that it can enable the use of HVFR fluids in recycled and produced waters, providing both cost and sustainability benefits. Secondly, these surfactant formulations can reduce the amount of HVFR required to obtain a certain target viscosity in brine, thereby reducing the likelihood and potential severity of formation damage from HVFR residue.
{"title":"Enhancing Performance of High Viscosity Friction Reducers HVFRs in Brine","authors":"Alhad Phatak, B. Seymour, Ginger Ren, Isaias Gonzalez","doi":"10.2118/204339-ms","DOIUrl":"https://doi.org/10.2118/204339-ms","url":null,"abstract":"\u0000 High Viscosity Friction Reducers (HVFRs) are often employed in hydraulic fracturing fluids to increase the proppant carrying capacity of slickwater fluids. However, it has been widely reported that the performance of HVFR fluids drops precipitously with even small amounts of salt. This study explores and reports the use of surfactants to alleviate the loss of performance of HVFR fluids due to salinity in the mix water. Fracturing fluids were prepared in the laboratory by mixing the HVFR at concentrations between 2 and 8 gal/1,000 gal with and without surfactant formulations. The viscosities of the fluids were measured on a TA Instruments DHR-3 rheometer using a concentric cylinder geometry. Both anionic and cationic HVFRs were tested with various surfactants. As expected, we observed that HVFR fluids display dramatic loss of viscosity with the addition of as little as 1% salt to the mix water. However, certain surfactant formulations were found to provide a significant boost in viscosity of HVFR fluids in brines over a wide range of shear rates. Increases in viscosity by a factor of as much as 10 times were observed, particularly at low shear rates. The ability of the surfactant formulations to enhance fluid viscosity was observed in both monovalent and divalent model brines, as well as brines that mimicked field produced water compositions. In addition, measurements were also performed in a slot flow device to determine if the results from the rheometer translated to proppant transport characteristics of the fluids. The slot flow results were found to correlate well with fluid viscosity measurements. The fluids containing the surfactant formulation transported nearly 4 times as much proppant as fluids not containing surfactant through a 2.5 ft. long rectangular slot of 0.5 in. thickness at a proppant concentration of 2 lb/gal. An obvious benefit of the approach proposed in this study is that it can enable the use of HVFR fluids in recycled and produced waters, providing both cost and sustainability benefits. Secondly, these surfactant formulations can reduce the amount of HVFR required to obtain a certain target viscosity in brine, thereby reducing the likelihood and potential severity of formation damage from HVFR residue.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"145 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91340958","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}
Yue Zhao, Z. Dai, Chong Dai, Xin Wang, Samridhdi Paudyal, Saebom Ko, Xuanzhu Yao, Cianna Leschied, A. Kan, M. Tomson
Scale inhibitors have been widely used for barite scale control. Our group has developed several barite crystallization and inhibition models to predict the crystallization and inhibition kinetics of pure barite with different inhibitors and calculate the minimum inhibitor concentration (MIC) required. However, instead of pure barite scale formation, the incorporation of Sr2+ can be frequently found in the oilfield, because of the coexistence of Ba2+ and Sr2+ in the produced water, which can influence the kinetics of crystallization and inhibition significantly. As a result, the MIC predicted could be off significantly. Therefore, in this study, the effect of Sr2+ on barite crystallization and inhibition kinetics is quantitatively investigated to evaluate the accuracy of MIC values under various conditions. The induction time of barite with different concentrations of Sr2+ was measured by laser apparatus without or with different concentrations of scale inhibitor diethylenetriamine penta(methylene phosphonic acid) (DTPMP) at the conditions: barite saturation index (SI) from 1.5 to 1.8; temperature (T) from 40 to 70 ℃; and [Sr2+]/[Ba2+] molar ratios from 0 to 15, all with celestite SI < 0. The results show that the induction time of the barite increases with [Sr2+]/[Ba2+] ratio at a fixed barite SI, T and DTPMP dosage. That means the MIC will be overestimated if it is calculated by previous semiempirical pure barite crystallization and inhibition models, without considering the presence of Sr2+. Based on the experimental results, the novel quantitative barite crystallization and inhibition models that include the influence of Sr2+ were developed for the first time as follows: Barite crystallization model with the influence of Sr2+: l o g 10 t 0 B a S O 4 , S r = ( 1.523 − 10.88 S I − 895.67 T ( K ) + 5477 S I × T ( K ) + 0.829 × [ C a 2 + ] ) + ( 0.823 S I + 85.44 T ( K ) − 0.667 ) × ( [ Sr 2 + ] [ B a 2 + ] ) Barite inhibition model including the influence of Sr2+ l o g 10 ( t i n h B a s o 4 , S r t 0 B a S O 4 , S r ) = b B a S O 4 , S r × C i n h l o g 10 b B a S O 4 , S r = ( − 2.187 − 1.411 × S I + 1329.29 T ( K ) + 0.153 × p H ) + ( 0.0983 × S I − 74.66 T ( K ) + 0.099 ) × ( [ Sr 2 + ] [ B a 2 + ] ) These novel models are in good agreement with the experimental data. They are used to predict the induction time and MIC more accurately at these common Ba2+ and Sr2+ coexisting scenarios. The observations and new models proposed in this study will significantly improve the barite scale management when Ba2+ and Sr2+ coexist in the oilfield.
阻垢剂已广泛应用于重晶石阻垢。本小组开发了几种重晶石结晶和抑制模型，用于预测不同抑制剂对纯重晶石的结晶和抑制动力学，并计算所需的最小抑制剂浓度(MIC)。然而，由于采出水中Ba2+和Sr2+共存，在油田中经常发现Sr2+的掺入，而不是纯粹的重晶石结垢，这对结晶和抑制动力学有显著影响。因此，MIC的预测可能会有很大偏差。因此，本研究定量研究了Sr2+对重晶石结晶和抑制动力学的影响，以评价不同条件下MIC值的准确性。在重晶石饱和指数(SI)为1.5 ~ 1.8的条件下，用激光测定仪测定了不同浓度Sr2+对重晶石的诱导时间。温度(T) 40 ~ 70℃;和[Sr2+]/[Ba2+]摩尔比为0 ~ 15，均为SI < 0。结果表明:在一定的重晶石SI、T和DTPMP用量下，随着[Sr2+]/[Ba2+]比值的增加，重晶石的诱导时间增加;这意味着如果用以前的半经验纯重晶石结晶和抑制模型来计算，而不考虑Sr2+的存在，MIC将被高估。基于实验结果，首次建立了考虑Sr2+影响的新型重晶石结晶与抑制定量模型:Sr2+影响的重晶石结晶模型:l o g 10 t 0 B S o 4, r =(1.523−10.88年代我−895.67 t (K) + 5477年代我××t (K) + 0.829 (C 2 + ] ) + ( 0.823 S I + 85.44 T (K)−0.667)×([老2 +][B 2 +])重晶石抑制模型的影响包括Sr2 + l o g 10 (T I n h B S o 4 S r T 0 B S o 4, S r) = B B S o 4, S r×C I n h l o g 10 B B S o 4,Sr =(−2.187−1.411 × S I + 1329.29 T (K) + 0.153 × p H) + (0.0983 × S I−74.66 T (K) + 0.099) × ([Sr 2 +] [B a 2 +])。在常见的Ba2+和Sr2+共存的情况下，它们可以更准确地预测诱导时间和MIC。本研究的观测结果和新模型将显著改善油田中Ba2+和Sr2+共存时的重晶石垢管理。
{"title":"A Quantitative Study of Sr2+ Impact on Barite Crystallization and Inhibition Kinetics","authors":"Yue Zhao, Z. Dai, Chong Dai, Xin Wang, Samridhdi Paudyal, Saebom Ko, Xuanzhu Yao, Cianna Leschied, A. Kan, M. Tomson","doi":"10.2118/204361-ms","DOIUrl":"https://doi.org/10.2118/204361-ms","url":null,"abstract":"\u0000 Scale inhibitors have been widely used for barite scale control. Our group has developed several barite crystallization and inhibition models to predict the crystallization and inhibition kinetics of pure barite with different inhibitors and calculate the minimum inhibitor concentration (MIC) required. However, instead of pure barite scale formation, the incorporation of Sr2+ can be frequently found in the oilfield, because of the coexistence of Ba2+ and Sr2+ in the produced water, which can influence the kinetics of crystallization and inhibition significantly. As a result, the MIC predicted could be off significantly. Therefore, in this study, the effect of Sr2+ on barite crystallization and inhibition kinetics is quantitatively investigated to evaluate the accuracy of MIC values under various conditions. The induction time of barite with different concentrations of Sr2+ was measured by laser apparatus without or with different concentrations of scale inhibitor diethylenetriamine penta(methylene phosphonic acid) (DTPMP) at the conditions: barite saturation index (SI) from 1.5 to 1.8; temperature (T) from 40 to 70 ℃; and [Sr2+]/[Ba2+] molar ratios from 0 to 15, all with celestite SI < 0. The results show that the induction time of the barite increases with [Sr2+]/[Ba2+] ratio at a fixed barite SI, T and DTPMP dosage. That means the MIC will be overestimated if it is calculated by previous semiempirical pure barite crystallization and inhibition models, without considering the presence of Sr2+. Based on the experimental results, the novel quantitative barite crystallization and inhibition models that include the influence of Sr2+ were developed for the first time as follows:\u0000 Barite crystallization model with the influence of Sr2+:\u0000 l o g 10 t 0 B a S O 4 , S r = ( 1.523 − 10.88 S I − 895.67 T ( K ) + 5477 S I × T ( K ) + 0.829 × [ C a 2 + ] ) + ( 0.823 S I + 85.44 T ( K ) − 0.667 ) × ( [ Sr 2 + ] [ B a 2 + ] )\u0000 Barite inhibition model including the influence of Sr2+\u0000 l o g 10 ( t i n h B a s o 4 , S r t 0 B a S O 4 , S r ) = b B a S O 4 , S r × C i n h l o g 10 b B a S O 4 , S r = ( − 2.187 − 1.411 × S I + 1329.29 T ( K ) + 0.153 × p H ) + ( 0.0983 × S I − 74.66 T ( K ) + 0.099 ) × ( [ Sr 2 + ] [ B a 2 + ] )\u0000 These novel models are in good agreement with the experimental data. They are used to predict the induction time and MIC more accurately at these common Ba2+ and Sr2+ coexisting scenarios. The observations and new models proposed in this study will significantly improve the barite scale management when Ba2+ and Sr2+ coexist in the oilfield.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84308802","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 low and ultra-low permeability reservoirs in China, such as the Changqing, Jidong, and Daqing peripheral oil fields, often apply CO2 as a flooding medium to enhance oil recovery. A serial of water-rock interactions will be occurred among the CO2, formation rock, and formation water under the HT/HP conditions. The pH value of the formation will be converted to acidity accordingly. As a side effect, the traditional guar-based fracturing fluids in an alkaline range, such as the borate cross-linked hydroxypropyl guar gum (HPG), cannot result in an effective hydrofracturing operation due to the incompatibility. Consequently, developing an acidic fracturing fluid system with a satisfactory performance is an imperative. Acidic fracturing fluids, such as the zirconium cross-linked carboxymethyl hydroxypropyl guar gum (CMHPG), can protect the formation during the hydrofracturing process from the damage arising from the swelling and migration of the clay particles. However, the shortcomings of the uncontrollable viscosity growth and the irreversible shear-thinning behavior limit the large-scale use of the acidic fracturing fluids. In this work, a novel organic zirconium cross-linker synthesized in the laboratory was applied to control and delay the cross-link reaction under the acidic condition. The ligands coordinated to the zirconium center were the L-lactate and ethylene glycol. The thickener used was the CMHPG at a low loading of 0.3% (approximately 25 pptg). Meanwhile, the surface functionalized metallic phase (1T-phase) molybdenum disulfide (MoS2) nanosheets were employed to improve the rheological performance of the zirconium cross-linked CMHPG fracturing fluid. The modification reagent utilized was the L-cysteine. The morphology, structure, and property of the fabricated functionalized 1T-MoS2 (Cys-1T-MoS2) nanosheets were systematically characterized using the transmission electron microscopy (TEM), scanning electron microscopy (SEM), Raman spectroscopy, X-ray diffraction (XRD), X-ray photoelectron spectroscopy (XPS), Fourier transform infrared spectroscopy (FTIR), and thermogravimetric analysis (TGA) measurements. The results of the characterization tests demonstrated a successful functionalization of the 1T-MoS2 nanosheets with L-cysteine. Then, the effects of this new nanosheet-enhanced zirconium cross-linked CMHPG fracturing fluid systems with different cross-linker and nanosheet loadings on gelation performance were systematically assessed employing the Sydansk bottle testing method combined with a rheometer under the controlled-stress or controlled-rate modes. The results indicated that the nanosheet-enhanced fracturing fluid had a desirable delayed property. Compared with the blank fracturing fluid (without nanosheets), the nanosheet-enhanced fracturing fluid had a much better shear-tolerant and shear-recovery performance.
{"title":"Improved Gelation Performance of an Acidic Low-Polymer Loading Zirconium Cross-Linked CMHPG Fracturing Fluid by Surface Functionalized 1T-Phase Molybdenum Disulfide Nanosheets","authors":"Kaiyu Zhang, J. Hou, Zhuojing Li","doi":"10.2118/204308-ms","DOIUrl":"https://doi.org/10.2118/204308-ms","url":null,"abstract":"\u0000 The low and ultra-low permeability reservoirs in China, such as the Changqing, Jidong, and Daqing peripheral oil fields, often apply CO2 as a flooding medium to enhance oil recovery. A serial of water-rock interactions will be occurred among the CO2, formation rock, and formation water under the HT/HP conditions. The pH value of the formation will be converted to acidity accordingly. As a side effect, the traditional guar-based fracturing fluids in an alkaline range, such as the borate cross-linked hydroxypropyl guar gum (HPG), cannot result in an effective hydrofracturing operation due to the incompatibility. Consequently, developing an acidic fracturing fluid system with a satisfactory performance is an imperative.\u0000 Acidic fracturing fluids, such as the zirconium cross-linked carboxymethyl hydroxypropyl guar gum (CMHPG), can protect the formation during the hydrofracturing process from the damage arising from the swelling and migration of the clay particles. However, the shortcomings of the uncontrollable viscosity growth and the irreversible shear-thinning behavior limit the large-scale use of the acidic fracturing fluids. In this work, a novel organic zirconium cross-linker synthesized in the laboratory was applied to control and delay the cross-link reaction under the acidic condition. The ligands coordinated to the zirconium center were the L-lactate and ethylene glycol. The thickener used was the CMHPG at a low loading of 0.3% (approximately 25 pptg). Meanwhile, the surface functionalized metallic phase (1T-phase) molybdenum disulfide (MoS2) nanosheets were employed to improve the rheological performance of the zirconium cross-linked CMHPG fracturing fluid. The modification reagent utilized was the L-cysteine. The morphology, structure, and property of the fabricated functionalized 1T-MoS2 (Cys-1T-MoS2) nanosheets were systematically characterized using the transmission electron microscopy (TEM), scanning electron microscopy (SEM), Raman spectroscopy, X-ray diffraction (XRD), X-ray photoelectron spectroscopy (XPS), Fourier transform infrared spectroscopy (FTIR), and thermogravimetric analysis (TGA) measurements. The results of the characterization tests demonstrated a successful functionalization of the 1T-MoS2 nanosheets with L-cysteine. Then, the effects of this new nanosheet-enhanced zirconium cross-linked CMHPG fracturing fluid systems with different cross-linker and nanosheet loadings on gelation performance were systematically assessed employing the Sydansk bottle testing method combined with a rheometer under the controlled-stress or controlled-rate modes. The results indicated that the nanosheet-enhanced fracturing fluid had a desirable delayed property. Compared with the blank fracturing fluid (without nanosheets), the nanosheet-enhanced fracturing fluid had a much better shear-tolerant and shear-recovery performance.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83994825","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}
Selection of "first fill" demulsifiers for new, undeveloped, oil fields has significant limitations, typically relying on data from test work with synthetic emulsion created in a laboratory using highly contaminated drilling samples of crude oil. Additional separation challenges related to offshore production of high viscosity, low API crude oil, from a low temperature reservoir results in a low probability of success in selecting a suitable first fill demulsifier using the traditional bottle test alone. To give improved speed of oil/water separation, water quality, interface quality and top oil dehydration, samples of chemical free oil and produced water were used to screen alternative existing products against the base case demulsifier via bottle testing. The emulsions were created using a high shear stirrer to mimic the system conditions of the wells coming online and water droplet size within the emulsion was determined via cross polarizing thermal microscopy. For the purposes of these tests, demulsifier performance was ranked on speed and completeness of separation, interface quality, water quality and grind out (BS&W) characteristics. Several differences were observed between the initial and subsequent test work. The low shear emulsion created in the early work was found to be very unstable, separating easily with no residual emulsion in the crude oil. The emulsion created under high shear conditions gave a much closer correlation in terms of water droplet distribution to that measured during the field test and resulted in a much more stable emulsion that was more difficult to separate and typically left unresolved emulsion in the oil after the bulk of the water had separated. Whilst the original demulsifier recommendation was still able to facilitate separation it was found that it was no longer the optimum product, with other previously disregarded products able to provide a higher level of performance on the high shear emulsion. This paper demonstrates that a higher level of performance was achieved with an enhanced screening process, namely through high shear stirring and confirmation of water droplet size within the emulsion. When added to the standard bottle testing conditions, the development of demulsifiers can better ensure an optimum result, fit for purpose for the application.
{"title":"Adaptation of Test Methodology and the Evolution of a Demulsifier Formulation for a Heavy Oil Start-Up","authors":"A. White, R. Miller, E. Bellu, J. Wylde","doi":"10.2118/204293-ms","DOIUrl":"https://doi.org/10.2118/204293-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Selection of \"first fill\" demulsifiers for new, undeveloped, oil fields has significant limitations, typically relying on data from test work with synthetic emulsion created in a laboratory using highly contaminated drilling samples of crude oil. Additional separation challenges related to offshore production of high viscosity, low API crude oil, from a low temperature reservoir results in a low probability of success in selecting a suitable first fill demulsifier using the traditional bottle test alone.\u0000 \u0000 \u0000 \u0000 To give improved speed of oil/water separation, water quality, interface quality and top oil dehydration, samples of chemical free oil and produced water were used to screen alternative existing products against the base case demulsifier via bottle testing. The emulsions were created using a high shear stirrer to mimic the system conditions of the wells coming online and water droplet size within the emulsion was determined via cross polarizing thermal microscopy. For the purposes of these tests, demulsifier performance was ranked on speed and completeness of separation, interface quality, water quality and grind out (BS&W) characteristics.\u0000 \u0000 \u0000 \u0000 Several differences were observed between the initial and subsequent test work. The low shear emulsion created in the early work was found to be very unstable, separating easily with no residual emulsion in the crude oil. The emulsion created under high shear conditions gave a much closer correlation in terms of water droplet distribution to that measured during the field test and resulted in a much more stable emulsion that was more difficult to separate and typically left unresolved emulsion in the oil after the bulk of the water had separated. Whilst the original demulsifier recommendation was still able to facilitate separation it was found that it was no longer the optimum product, with other previously disregarded products able to provide a higher level of performance on the high shear emulsion.\u0000 \u0000 \u0000 \u0000 This paper demonstrates that a higher level of performance was achieved with an enhanced screening process, namely through high shear stirring and confirmation of water droplet size within the emulsion. When added to the standard bottle testing conditions, the development of demulsifiers can better ensure an optimum result, fit for purpose for the application.\u0000","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"261 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86715089","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}
Qichao Lv, Tongke Zhou, Xing Zhang, Xinshu Guo, Z. Dong
CO2 foams have been used for a long time for enhanced oil recovery (EOR) and carbon capture, utilization, and storage. Note that conventional CO2 foam focuses on mobility control and storage of bare CO2. However, this technology has suffered from low storage efficiency and EOR because of foam instability. In this study, the geological storage of CO2 and coal fly ash (CFA) using Pickering foam for EOR was explored. The aim is to obtain an inexpensive method for EOR and storage of greenhouse gases and atmospheric pollutants. The Pickering foam was prepared using Waring blender method. The experiments were conducted to evaluate CO2/liquid interface enhancement by measuring the interfacial tension and interfacial viscoelastic modulus. As per the heterogeneous sandpack flooding experiments, the profile control capacity and the performance of oil displacement using CO2 foam enhanced by CFA were investigated. The amount of storage from dynamic aspects of CO2 and CFA was measured to demonstrate the storage law. The stability of aqueous foam was improved significantly after the addition of CFA. The half-life time of foam stabilized by CFA particles increased by more than about 11 times than that of foam without CFA particles. The interfacial dilatational viscoelastic modulus of CO2/foaming solution increased with CFA particle concentration increasing, indicating the interface transformed from liquid-like to solid-like. Flooding experiments in heterogeneous porous media showed that more produced fluid was displaced from the relatively low-permeability sandpack after the injection of CO2 foam with CFA. The oil recovery by CFA stabilized foam was improved by ~28.3% than that of foam without CFA particles. And the sequestration of CO2 in heterogeneous porous media was enhanced with the addition of CFA to CO2 foam, and the CFA stabilized foam displayed a strong resistance to water erosion for the storage of CO2 and CFA. This work introduces a win–win method for EOR and storage of CO2 and atmospheric pollutant particles. CFA from coal combustion was used as an enhancer for CO2 foam, which improved the interfacial dilatational viscoelasticity of foam film and the dynamic storage of CO2. Furthermore, the storage of CO2 and CFA contributed to improvement in sweep efficiency, and thus EOR.
{"title":"Storage of CO2 and Coal Fly Ash using Pickering Foam for Enhanced Oil Recovery","authors":"Qichao Lv, Tongke Zhou, Xing Zhang, Xinshu Guo, Z. Dong","doi":"10.2118/204330-ms","DOIUrl":"https://doi.org/10.2118/204330-ms","url":null,"abstract":"\u0000 CO2 foams have been used for a long time for enhanced oil recovery (EOR) and carbon capture, utilization, and storage. Note that conventional CO2 foam focuses on mobility control and storage of bare CO2. However, this technology has suffered from low storage efficiency and EOR because of foam instability. In this study, the geological storage of CO2 and coal fly ash (CFA) using Pickering foam for EOR was explored. The aim is to obtain an inexpensive method for EOR and storage of greenhouse gases and atmospheric pollutants.\u0000 The Pickering foam was prepared using Waring blender method. The experiments were conducted to evaluate CO2/liquid interface enhancement by measuring the interfacial tension and interfacial viscoelastic modulus. As per the heterogeneous sandpack flooding experiments, the profile control capacity and the performance of oil displacement using CO2 foam enhanced by CFA were investigated. The amount of storage from dynamic aspects of CO2 and CFA was measured to demonstrate the storage law.\u0000 The stability of aqueous foam was improved significantly after the addition of CFA. The half-life time of foam stabilized by CFA particles increased by more than about 11 times than that of foam without CFA particles. The interfacial dilatational viscoelastic modulus of CO2/foaming solution increased with CFA particle concentration increasing, indicating the interface transformed from liquid-like to solid-like. Flooding experiments in heterogeneous porous media showed that more produced fluid was displaced from the relatively low-permeability sandpack after the injection of CO2 foam with CFA. The oil recovery by CFA stabilized foam was improved by ~28.3% than that of foam without CFA particles. And the sequestration of CO2 in heterogeneous porous media was enhanced with the addition of CFA to CO2 foam, and the CFA stabilized foam displayed a strong resistance to water erosion for the storage of CO2 and CFA.\u0000 This work introduces a win–win method for EOR and storage of CO2 and atmospheric pollutant particles. CFA from coal combustion was used as an enhancer for CO2 foam, which improved the interfacial dilatational viscoelasticity of foam film and the dynamic storage of CO2. Furthermore, the storage of CO2 and CFA contributed to improvement in sweep efficiency, and thus EOR.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77695871","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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