The effects of H2S on system integrity, sulphide scaling potential and health and safety in oil and gas production is well recognized and understood. However, as part of a wider study on pH dependent scale predictions, the authors have identified an additional challenge associated with the presence and/or development of H2S in reservoirs containing carbonates: higher H2S concentration reflects in higher calcium carbonate scaling potential. The intention of this work is to demonstrate the impact of H2S using a real field case scenario and investigate how the variability in water cut, aqueous phase composition, CO2 and H2S concentration can impact the well carbonate scaling potential and ultimately its productivity. To model pH dependent scales correctly, it is necessary to integrate PVT calculations with the aqueous phase thermodynamic mineral scaling calculations. This has been extensively discussed in previous publications by the authors. For this work, a commercial integrated PVT and scale prediction software package was used to determine the scale prediction profile from reservoir to the first stage of topside separation. In addition, to investigate the impact of PVT on the final results, a second PVT software employing a different equation of state (EOS) is used and the results obtained from this calculations are coupled with the same aqueous phase model using the Heriot-Watt scale prediction workflow. The well selected for this study shows productivity issues as well as signs of presence of calcium carbonate scale. However, scale prediction calculations carried out in the past did not show any potential for carbonate scale formation at the given conditions. After rigorously accounting for variations in water cut over time, as well as for increased H2S due to reservoir souring, our work clearly shows a correlation between a gradual loss of well productivity and carbonate scaling potential. This work clearly demonstrates the impact of H2S on calcium carbonate scaling potential and highlights the importance of correctly modelling CO2 and H2S partitioning in gas/oil/water at the different stages of production, from reservoir to topside separation. Following this study, it has also been possible to offer specific well treatment and testing recommendations to verify the results and try to obtain improvements in production efficiency. Moreover, the application of our approach to a real field scenario shows how some field findings associated with carbonate scale problems can be explained only by correctly modelling the full three phase system (oil, gas and water). Some aspects of this approach are frequently overlooked and not linked correctly to carbonate scale formation.
{"title":"The Impact of H2S on Carbonate Scaling Risk. A Field Case Study","authors":"Giulia Ness, K. Sorbie, N. Lugo, C. Kelly","doi":"10.2118/193583-MS","DOIUrl":"https://doi.org/10.2118/193583-MS","url":null,"abstract":"\u0000 The effects of H2S on system integrity, sulphide scaling potential and health and safety in oil and gas production is well recognized and understood. However, as part of a wider study on pH dependent scale predictions, the authors have identified an additional challenge associated with the presence and/or development of H2S in reservoirs containing carbonates: higher H2S concentration reflects in higher calcium carbonate scaling potential. The intention of this work is to demonstrate the impact of H2S using a real field case scenario and investigate how the variability in water cut, aqueous phase composition, CO2 and H2S concentration can impact the well carbonate scaling potential and ultimately its productivity.\u0000 To model pH dependent scales correctly, it is necessary to integrate PVT calculations with the aqueous phase thermodynamic mineral scaling calculations. This has been extensively discussed in previous publications by the authors. For this work, a commercial integrated PVT and scale prediction software package was used to determine the scale prediction profile from reservoir to the first stage of topside separation. In addition, to investigate the impact of PVT on the final results, a second PVT software employing a different equation of state (EOS) is used and the results obtained from this calculations are coupled with the same aqueous phase model using the Heriot-Watt scale prediction workflow.\u0000 The well selected for this study shows productivity issues as well as signs of presence of calcium carbonate scale. However, scale prediction calculations carried out in the past did not show any potential for carbonate scale formation at the given conditions. After rigorously accounting for variations in water cut over time, as well as for increased H2S due to reservoir souring, our work clearly shows a correlation between a gradual loss of well productivity and carbonate scaling potential.\u0000 This work clearly demonstrates the impact of H2S on calcium carbonate scaling potential and highlights the importance of correctly modelling CO2 and H2S partitioning in gas/oil/water at the different stages of production, from reservoir to topside separation. Following this study, it has also been possible to offer specific well treatment and testing recommendations to verify the results and try to obtain improvements in production efficiency.\u0000 Moreover, the application of our approach to a real field scenario shows how some field findings associated with carbonate scale problems can be explained only by correctly modelling the full three phase system (oil, gas and water). Some aspects of this approach are frequently overlooked and not linked correctly to carbonate scale formation.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80362130","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}
Surfactant EOR received attraction due to its extreme capability to increase displacement efficiency by altering the wettability, lowering the oil/water interfacial tension and ultimately mobilizing the residual oil. However, surfactant systems are widely acknowledged to have large adsorption on rock/clay/sediment solid surfaces, which may result in concentration loss, thus impair the effectiveness of the chemical solution and turn the process into an economically unfeasible case. Surfactant adsorption can be affected by the adsorbents, surfactant structure, experimental temperature and some other factors. Also, the driving force for adsorption varies with different surfactants types. Generally speaking, electrostatic interaction is more prominent for those anionic surfactants, while hydrophobic interaction is more common for nonionic type. In this paper, the static adsorption behaviors of two surfactants (A1 and N1) on Bakken minerals and Berea sandstone in high salinity and high temperature Bakken conditions (salinity≈290,000 mg/L, temperature=80~105 °C) were studied using spectrometric iodine method, where 0.1 mM I2-0.2 mM KI solution was used as a color developing agent. The primary stability indicated that both surfactants have high compatibility with the Bakken formation brine at high temperature, and their critical micelle concentrations showed a small decrease in the presence of high saline brine. Bakken mineral is relatively complicate, which is composed of quartz, dolomite, calcite and clay, while Berea sandstone contains over 75 wt% quartz. Herein, the effects of surfactant concentration, surfactant type, temperature, adsorbents and salinity on adsorption density were covered, and the impacts of surfactant concentration and adsorbents were found to be more significant. Due to the higher specific surface area and high clay content of Bakken minerals, both anionic surfactant blend A1 and nonionic surfactant blend N1 have pretty high adsorption on Bakken minerals, and the specific adsorption densities of 1000 mg/L surfactant solution were calculated to be 1.74 mg/m2 and 1.69 mg/m2, respectively. Meanwhile, the results also indicated that though the applied surfactant concentration is relatively low, the concentration loss due to adsorption should never be overlooked. Future study on how to effectively reduce the adsorption of surfactant especially in those clay-rich formations is of great significance.
表面活性剂提高采收率受到青睐，因为它能够通过改变润湿性、降低油水界面张力并最终动员残余油来提高驱油效率。然而，表面活性剂体系被广泛认为在岩石/粘土/沉积物固体表面有很大的吸附作用，这可能导致浓度损失，从而影响化学溶液的有效性，并使该工艺在经济上不可行。表面活性剂的吸附受吸附剂、表面活性剂结构、实验温度等因素的影响。不同表面活性剂的吸附驱动力也不同。一般来说，阴离子型表面活性剂的静电相互作用更为突出，而非离子型表面活性剂的疏水相互作用更为常见。本文以0.1 mM i2 ~ 0.2 mM KI溶液为显色剂，采用光谱碘法研究了高盐高温Bakken条件下(盐度≈290,000 mg/L，温度=80~105℃)两种表面活性剂A1和N1在Bakken矿物和Berea砂岩上的静态吸附行为。初级稳定性表明，两种表面活性剂在高温下与Bakken地层盐水具有较高的相容性，且在高盐盐水存在下，其临界胶束浓度略有下降。巴肯的矿物相对复杂，主要由石英、白云岩、方解石和粘土组成，而伯里亚砂岩的石英含量超过75%。研究了表面活性剂浓度、表面活性剂类型、温度、吸附剂和盐度对吸附密度的影响，发现表面活性剂浓度和吸附剂对吸附密度的影响更为显著。由于巴肯矿物具有较高的比表面积和较高的粘粒含量，阴离子表面活性剂混配A1和非离子表面活性剂混配N1对巴肯矿物均具有较高的吸附性能，计算出1000 mg/L表面活性剂溶液的比吸附密度分别为1.74 mg/m2和1.69 mg/m2。同时，研究结果还表明，虽然表面活性剂的使用浓度较低，但由于吸附而造成的浓度损失不容忽视。今后研究如何有效地减少表面活性剂的吸附，特别是在富粘土地层中，具有重要的意义。
{"title":"Static Adsorption of Surfactants on Bakken Rock Surfaces in High Temperature, High Salinity Conditions","authors":"Xun Zhong, H. Pu, Yanxia Zhou, J. Zhao","doi":"10.2118/193589-MS","DOIUrl":"https://doi.org/10.2118/193589-MS","url":null,"abstract":"\u0000 Surfactant EOR received attraction due to its extreme capability to increase displacement efficiency by altering the wettability, lowering the oil/water interfacial tension and ultimately mobilizing the residual oil. However, surfactant systems are widely acknowledged to have large adsorption on rock/clay/sediment solid surfaces, which may result in concentration loss, thus impair the effectiveness of the chemical solution and turn the process into an economically unfeasible case. Surfactant adsorption can be affected by the adsorbents, surfactant structure, experimental temperature and some other factors. Also, the driving force for adsorption varies with different surfactants types. Generally speaking, electrostatic interaction is more prominent for those anionic surfactants, while hydrophobic interaction is more common for nonionic type.\u0000 In this paper, the static adsorption behaviors of two surfactants (A1 and N1) on Bakken minerals and Berea sandstone in high salinity and high temperature Bakken conditions (salinity≈290,000 mg/L, temperature=80~105 °C) were studied using spectrometric iodine method, where 0.1 mM I2-0.2 mM KI solution was used as a color developing agent. The primary stability indicated that both surfactants have high compatibility with the Bakken formation brine at high temperature, and their critical micelle concentrations showed a small decrease in the presence of high saline brine. Bakken mineral is relatively complicate, which is composed of quartz, dolomite, calcite and clay, while Berea sandstone contains over 75 wt% quartz. Herein, the effects of surfactant concentration, surfactant type, temperature, adsorbents and salinity on adsorption density were covered, and the impacts of surfactant concentration and adsorbents were found to be more significant. Due to the higher specific surface area and high clay content of Bakken minerals, both anionic surfactant blend A1 and nonionic surfactant blend N1 have pretty high adsorption on Bakken minerals, and the specific adsorption densities of 1000 mg/L surfactant solution were calculated to be 1.74 mg/m2 and 1.69 mg/m2, respectively. Meanwhile, the results also indicated that though the applied surfactant concentration is relatively low, the concentration loss due to adsorption should never be overlooked. Future study on how to effectively reduce the adsorption of surfactant especially in those clay-rich formations is of great significance.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77645477","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. Pagel, Trey Tindall, T. Pursley, Timothy Sweeney, Zack Li, T. Lathrop, B. Sullivan, Greg Simpson
Oilfield produced waters are usually returned to the ground by either reinjecting into underground reservoirs for enhanced oil recovery or injecting in saltwater disposal wells (SWDW) for final disposal. SWDWs often receive waters from production wells with comingled brines. These brines contain residual oils, suspended solids, and additives (such as friction reducers, partially broken gels, biocides, scale and corrosion inhibitors). SWDWs experience declined well injectivity, due to damages from downhole buildup of particles, oils, and biofilms clogging well casing and tubing and plugging a well's perforations and the near wellbore matrix. To fix these problems, chemical treatments are often performed to restore the injectivity of the formations and reduce the injection pressure. Acids and solvents are frequently used to clear blockages of the wells and restore the permeability of the rock formation. Existing chemical treatments of SWDWs still face some challenges, including asphaltene and iron oxide and iron sulfide precipitation, and H2S formation from acid reaction with iron sulfides. Herein, we report the development and optimization of an innovative field SWDW chemical treatment program. We have successfully developed and optimized the new treatment method including three treating chemicals: hydrochloric acid (HCl), chlorine dioxide (ClO2), and a proprietary Complex nano Fluid (CnF®). Typically, CnF®, HCl, and ClO2 solutions are pumped sequentially downhole into the well formation, with the specific flush volumes of each chemical varying from well to well based on the wellbore configuration. The field application data collected from SWDWs in Haynesville Play and Permian Basin clearly demonstrate remarkable improvement in injectivity and pressure reduction parameters. In all cases, the new treatment combination provides great economic value, with investment payout time within a few weeks. The novel chemical treatment program is expected to have broad application in the treatment of SWDWs across a variety of geological formations in almost all basins.
{"title":"Rducing Backpressure and Enhancing Throughput of Saltwater Disposal Wells with Chlorine Dioxide and Complex Nano Fluids: Optimization and Case Studies","authors":"R. Pagel, Trey Tindall, T. Pursley, Timothy Sweeney, Zack Li, T. Lathrop, B. Sullivan, Greg Simpson","doi":"10.2118/193629-MS","DOIUrl":"https://doi.org/10.2118/193629-MS","url":null,"abstract":"\u0000 Oilfield produced waters are usually returned to the ground by either reinjecting into underground reservoirs for enhanced oil recovery or injecting in saltwater disposal wells (SWDW) for final disposal. SWDWs often receive waters from production wells with comingled brines. These brines contain residual oils, suspended solids, and additives (such as friction reducers, partially broken gels, biocides, scale and corrosion inhibitors). SWDWs experience declined well injectivity, due to damages from downhole buildup of particles, oils, and biofilms clogging well casing and tubing and plugging a well's perforations and the near wellbore matrix. To fix these problems, chemical treatments are often performed to restore the injectivity of the formations and reduce the injection pressure. Acids and solvents are frequently used to clear blockages of the wells and restore the permeability of the rock formation. Existing chemical treatments of SWDWs still face some challenges, including asphaltene and iron oxide and iron sulfide precipitation, and H2S formation from acid reaction with iron sulfides.\u0000 Herein, we report the development and optimization of an innovative field SWDW chemical treatment program. We have successfully developed and optimized the new treatment method including three treating chemicals: hydrochloric acid (HCl), chlorine dioxide (ClO2), and a proprietary Complex nano Fluid (CnF®). Typically, CnF®, HCl, and ClO2 solutions are pumped sequentially downhole into the well formation, with the specific flush volumes of each chemical varying from well to well based on the wellbore configuration. The field application data collected from SWDWs in Haynesville Play and Permian Basin clearly demonstrate remarkable improvement in injectivity and pressure reduction parameters. In all cases, the new treatment combination provides great economic value, with investment payout time within a few weeks. The novel chemical treatment program is expected to have broad application in the treatment of SWDWs across a variety of geological formations in almost all basins.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84516637","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}
N. Bhandari, M. Bhandari, I. Littlehales, J. Fidoe
Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified. A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan. As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications. Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.
{"title":"Development of a Novel Iron Sulfide Scale Inhibitor for Onshore US Application","authors":"N. Bhandari, M. Bhandari, I. Littlehales, J. Fidoe","doi":"10.2118/193599-MS","DOIUrl":"https://doi.org/10.2118/193599-MS","url":null,"abstract":"\u0000 Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified.\u0000 A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan.\u0000 As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications.\u0000 Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"113 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79329775","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}
Adsorption of surfactant onto rock surfaces is dependent upon a number of factors, including characteristics of both the adsorbent and surfactant molecules. Considering that surfactant-based unconventional means to improve oil recovery are strongly dependent on the interaction at the liquid/liquid interface between soluble surfactant solution and crude oil, loss of surfactant to liquid/solid interfaces can create a negative effect for some of these applications in terms of performance and economics. This study; therefore, focuses on investigating the adsorption mechanism of surfactants onto sandstone and limestone reservoir media. Besides quantifying how much surfactant is adsorbed, emphasis specifically on the effect of surfactant parameters on the adsorption capacity was evaluated. Although literature well documents that mineralogy, temperature, pH, inclusion of other chemicals, and salinity all play strong roles on the adsorption capacity of surfactants on a solid surface; all of these parameters, with exception of mineralogy, were maintained as constants for this work. Anionic alcohol propoxy sulfate, nonionic alcohol ethoxylate, and ether carboxylate surfactants were studied. Academic focus for this effort was placed on surfactant parameters being evaluated including the structure of the surfactant hydrophilic head group and the surfactant hydrophobic tail. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the complexity of this phenomenon. Experimental results show that various surfactant parameters affect the adsorption differently based on their interaction with different adsorbents. An increase in hydrophobicity appears to increase surfactant adsorption. This was observed through a number of different mechanisms including increasing percent of propylene oxide (PO) and increasing degree of hydrophobe branching of the surfactants. Conversely, increasing carbon chain length and keeping the percent of PO more constant appeared to show a general decrease in adsorption trend with alcohol propoxy sulfate and a discernible decrease in adsorption in sandstone versus limestone mineralogy. It was also observed that varying ratios of propylene oxide and ethylene oxide extensions to alcohol alkoxy sulfate molecules will have an influence on surfactant adsorption. Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. The findings from this study can be used to improve understanding on how the role of different surfactant parameters may affect surfactant adsorption. This will help lead to enhancements in designing surfactant molecular structures that in turn minimize adsorption to rock surfaces, while maintaining desired fluid performance for effective oil recovery.
{"title":"Role of Surfactant Structures on Surfactant-Rock Adsorption in Various Rock Types","authors":"Daniel Wilson, Laurie Poindexter, Thu T. Nguyen","doi":"10.2118/193595-MS","DOIUrl":"https://doi.org/10.2118/193595-MS","url":null,"abstract":"\u0000 Adsorption of surfactant onto rock surfaces is dependent upon a number of factors, including characteristics of both the adsorbent and surfactant molecules. Considering that surfactant-based unconventional means to improve oil recovery are strongly dependent on the interaction at the liquid/liquid interface between soluble surfactant solution and crude oil, loss of surfactant to liquid/solid interfaces can create a negative effect for some of these applications in terms of performance and economics.\u0000 This study; therefore, focuses on investigating the adsorption mechanism of surfactants onto sandstone and limestone reservoir media. Besides quantifying how much surfactant is adsorbed, emphasis specifically on the effect of surfactant parameters on the adsorption capacity was evaluated. Although literature well documents that mineralogy, temperature, pH, inclusion of other chemicals, and salinity all play strong roles on the adsorption capacity of surfactants on a solid surface; all of these parameters, with exception of mineralogy, were maintained as constants for this work.\u0000 Anionic alcohol propoxy sulfate, nonionic alcohol ethoxylate, and ether carboxylate surfactants were studied. Academic focus for this effort was placed on surfactant parameters being evaluated including the structure of the surfactant hydrophilic head group and the surfactant hydrophobic tail. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the complexity of this phenomenon. Experimental results show that various surfactant parameters affect the adsorption differently based on their interaction with different adsorbents. An increase in hydrophobicity appears to increase surfactant adsorption. This was observed through a number of different mechanisms including increasing percent of propylene oxide (PO) and increasing degree of hydrophobe branching of the surfactants. Conversely, increasing carbon chain length and keeping the percent of PO more constant appeared to show a general decrease in adsorption trend with alcohol propoxy sulfate and a discernible decrease in adsorption in sandstone versus limestone mineralogy. It was also observed that varying ratios of propylene oxide and ethylene oxide extensions to alcohol alkoxy sulfate molecules will have an influence on surfactant adsorption.\u0000 Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. The findings from this study can be used to improve understanding on how the role of different surfactant parameters may affect surfactant adsorption. This will help lead to enhancements in designing surfactant molecular structures that in turn minimize adsorption to rock surfaces, while maintaining desired fluid performance for effective oil recovery.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90044406","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}
Polylactic Acid (PLA) is increasingly used in the oil industry and specifically for diversion in matrix acidizing as evidenced by a number of field cases recently published. The solid polyester is particularly attractive due to its ability to degrade in the presence of water and heat, negating the need for cleanup fluids or complicated procedures. A majority of the analysis on the effectiveness of PLA thus far comprises experiments on artificially created slots, filter cake analysis, and field trials. This paper demonstrates the effect of PLA in wormholes developed by acidizing outcrop cores. In these experiments, a wormhole is generated in a portion of the core by limiting the amount of acid injected. Next, the PLA is injected into the core using a heavy brine suspension. Finally, more acid is injected until a wormhole breaks through the core. Computer Tomography (CT) scans are taken, and the pressure drop across the core is recorded at each stage. Experiments were conducted for a variety of initial wormhole lengths. It can be difficult to suspend PLA while injecting it through a core in a way that is benign to the core, acid, and PLA; and in a way that does not add any pressure drop or diversion due to viscosity changes. This paper describes and justifies a suitable method of keeping PLA suspended to allow its use in core flood experiments. The CT scans show that even when the PLA plugs the wormhole, additional acid tends to continue to develop the dominant wormhole. The pressure drop profiles show that the pressure drop due to PLA injection is proportional to the mass of PLA, both in the wormhole and on the core surface. The pressure profiles also show that there is an increased pressure drop due to PLA in the wormhole versus in a filter cake on the surface. This paper details a new method of visualizing and analyzing the effect of PLA in a multistage acidizing treatment. Empirical correlations are presented for estimating the pressure drop caused by PLA, both as a filter cake on the formation surface and as a filling inside wormholes. The correlations were incorporated in a comprehensive carbonate acidizing model to predict the diversion efficiency of PLA particles. The simulation is verified using published field trials of diversion treatments.
{"title":"Experimental Investigation of Particulate Polylactic Acid Diversion in Matrix Acidizing","authors":"R. Shirley, A. Hill","doi":"10.2118/193565-MS","DOIUrl":"https://doi.org/10.2118/193565-MS","url":null,"abstract":"\u0000 Polylactic Acid (PLA) is increasingly used in the oil industry and specifically for diversion in matrix acidizing as evidenced by a number of field cases recently published. The solid polyester is particularly attractive due to its ability to degrade in the presence of water and heat, negating the need for cleanup fluids or complicated procedures. A majority of the analysis on the effectiveness of PLA thus far comprises experiments on artificially created slots, filter cake analysis, and field trials. This paper demonstrates the effect of PLA in wormholes developed by acidizing outcrop cores.\u0000 In these experiments, a wormhole is generated in a portion of the core by limiting the amount of acid injected. Next, the PLA is injected into the core using a heavy brine suspension. Finally, more acid is injected until a wormhole breaks through the core. Computer Tomography (CT) scans are taken, and the pressure drop across the core is recorded at each stage. Experiments were conducted for a variety of initial wormhole lengths.\u0000 It can be difficult to suspend PLA while injecting it through a core in a way that is benign to the core, acid, and PLA; and in a way that does not add any pressure drop or diversion due to viscosity changes. This paper describes and justifies a suitable method of keeping PLA suspended to allow its use in core flood experiments. The CT scans show that even when the PLA plugs the wormhole, additional acid tends to continue to develop the dominant wormhole. The pressure drop profiles show that the pressure drop due to PLA injection is proportional to the mass of PLA, both in the wormhole and on the core surface. The pressure profiles also show that there is an increased pressure drop due to PLA in the wormhole versus in a filter cake on the surface.\u0000 This paper details a new method of visualizing and analyzing the effect of PLA in a multistage acidizing treatment. Empirical correlations are presented for estimating the pressure drop caused by PLA, both as a filter cake on the formation surface and as a filling inside wormholes. The correlations were incorporated in a comprehensive carbonate acidizing model to predict the diversion efficiency of PLA particles. The simulation is verified using published field trials of diversion treatments.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87552299","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}
J. I. Aguiar, Claudia Mazzeo, R. Garan, A. Punase, Syed Razavi, A. Mahmoudkhani
Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.
{"title":"What Can We Learn from Analysis of Field Asphaltenes Deposits? Enhancing Product Development Through Knowledge-Based Field-to-Lab-to-Field Approach","authors":"J. I. Aguiar, Claudia Mazzeo, R. Garan, A. Punase, Syed Razavi, A. Mahmoudkhani","doi":"10.2118/193604-MS","DOIUrl":"https://doi.org/10.2118/193604-MS","url":null,"abstract":"\u0000 Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75288144","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}
Inflow Control Devices (ICDs) are being increasingly used in complex, heterogeneous reservoirs to make the inflow profile more uniform, delay breakthrough of water and/or gas and limit differential depletion, which can lead to crossflow and other detrimental phenomena. However, ICDs not only alter inflow behaviour: they also affect outflow of fluid during chemical treatments, such as scale squeezes, stimulation, etc., which may be applied periodically during well life. Methods to account for the additional flow resistance from ICDs when predicting placement of bullheaded treatments are discussed in this paper, in particular, to evaluate whether a theoretical approach based upon Bernoulli's Theorem leads to sufficiently accurate predictions in the absence of laboratory correlations between pressure drop across the ICD and flow rate. This approach may also become significant where the laboratory calibration might be expected to have changed during well life, such as, under the influence of erosion. The paper describes two analytical methods of simulating placement in a multi-zone well in a heterogeneous reservoir in the Middle East: the first is empirical and models the pressure drop using an equation derived from calibration data in the laboratory; the second uses the Bernoulli equation, and is theoretical. For the empirical approach, the laboratory-based pressure-drop/flowrate calibration data were fitted to an equation, with parameters that depended upon the nozzle dimensions. The theoretical approach calculated the pressure drop using the Bernoulli equation for a cylindrical ICD nozzle. Both methods were used to simulate placement of a generic scale-inhibitor squeeze treatment and the corresponding chemical returns for each zone in the well. In general, the differences in the predictions between the two models were found to be very minor, showing that a theoretical approach is sufficiently accurate to design and evaluate chemical treatments in wells fitted with ICDs in most cases. This means a very rapid analytical approach can be used to design and evaluate near-wellbore treatments in such wells without resorting to much more complex, numerical-based reservoir simulators, even when calibration data about the ICD performance are not available.
{"title":"A Summary of Analytical Methods to Simulate Chemical Treatments in ICD Completed Wells","authors":"A. Kaur, R. Stalker, G. Graham, D. Frigo","doi":"10.2118/193542-MS","DOIUrl":"https://doi.org/10.2118/193542-MS","url":null,"abstract":"\u0000 Inflow Control Devices (ICDs) are being increasingly used in complex, heterogeneous reservoirs to make the inflow profile more uniform, delay breakthrough of water and/or gas and limit differential depletion, which can lead to crossflow and other detrimental phenomena. However, ICDs not only alter inflow behaviour: they also affect outflow of fluid during chemical treatments, such as scale squeezes, stimulation, etc., which may be applied periodically during well life.\u0000 Methods to account for the additional flow resistance from ICDs when predicting placement of bullheaded treatments are discussed in this paper, in particular, to evaluate whether a theoretical approach based upon Bernoulli's Theorem leads to sufficiently accurate predictions in the absence of laboratory correlations between pressure drop across the ICD and flow rate. This approach may also become significant where the laboratory calibration might be expected to have changed during well life, such as, under the influence of erosion.\u0000 The paper describes two analytical methods of simulating placement in a multi-zone well in a heterogeneous reservoir in the Middle East: the first is empirical and models the pressure drop using an equation derived from calibration data in the laboratory; the second uses the Bernoulli equation, and is theoretical. For the empirical approach, the laboratory-based pressure-drop/flowrate calibration data were fitted to an equation, with parameters that depended upon the nozzle dimensions. The theoretical approach calculated the pressure drop using the Bernoulli equation for a cylindrical ICD nozzle. Both methods were used to simulate placement of a generic scale-inhibitor squeeze treatment and the corresponding chemical returns for each zone in the well. In general, the differences in the predictions between the two models were found to be very minor, showing that a theoretical approach is sufficiently accurate to design and evaluate chemical treatments in wells fitted with ICDs in most cases.\u0000 This means a very rapid analytical approach can be used to design and evaluate near-wellbore treatments in such wells without resorting to much more complex, numerical-based reservoir simulators, even when calibration data about the ICD performance are not available.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78808981","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}
M. Gutierrez, S. Gaona, Fernando Enrique Calvete, Jesús Botett, J. V. Ferrari
About half of the world's oil reserves are in carbonate reservoirs, and most of these formations are mixed-wet or oil-wet and fractured, with extremely heterogeneous porosities and permeabilities. Implementation of enhanced oil recovery (EOR) techniques in this kind of reservoir is essential to achieve peak oil production and increase the recovery factor. Chemical EOR (CEOR) processes have been studied for many years in carbonate reservoirs but are not usually economically viable. Surfactant flooding has been considered as one of the most promising techniques among the chemical recovery methods due to the capacity of some surfactants to alter the carbonate rocks' wettability. However, the process is economically feasible only when losses of surfactant caused by adsorption into the porous media are decreased. Adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces. In general, the adsorption of cationic surfactants on carbonates is lower in comparison with other surfactants. Nevertheless, the high cost of cationic surfactants compared to anionic ones has led to studies aiming to evaluate the injection of the latter in the presence of a sacrificial agent in order to reduce the adsorption caused by interaction between the negative charges of the surfactant and positive charges on the carbonate surface. This work aims to study the effect of the presence of two chemicals, normally applied as scaling and corrosion inhibitors, on reducing the static adsorption of an anionic sodium olefin sulfonate surfactant on a carbonate rock. Water soluble poly(sodium methacrylate) (PSM) and diethanolamine (DEA) were evaluated as sacrificial agents in concentrations close to their scaling and corrosion inhibitor functions, respectively, to verify their sacrificial role in a co-injection chemical scenario. Adsorption studies were carried out using a pulverized carbonate rock in which low-salinity water was used as the base medium. Aqueous stability tests were carried out, which made it possible to select the correct salinity for the solutions of surfactant. Surface tension measurements were used as an indirect approach to study the adsorption of the surfactant in the presence and absence of PSM and DEA. Individually, PSM presented the best performance in reducing the adsorption of the anionic surfactant, while the DEA showed an almost null effect. However, when the chemicals were mixed, a synergistic effect was observed. The performance of PSM can probably be attributed to a steric effect of an adsorbed layer of polymer. It will be shown that even at lower concentrations, co-injection chemicals which are used for targeting other issues, such as scaling and corrosion inhibitors, may play the role of a sacrificial agent in reducing the adsorption of anionic surfactants, which is a concern in application to carbonate reservoirs.
{"title":"Effect of Scaling and Corrosion Inhibitors on the Static Adsorption of an Anionic Surfactant on a Carbonate Rock","authors":"M. Gutierrez, S. Gaona, Fernando Enrique Calvete, Jesús Botett, J. V. Ferrari","doi":"10.2118/193546-MS","DOIUrl":"https://doi.org/10.2118/193546-MS","url":null,"abstract":"\u0000 About half of the world's oil reserves are in carbonate reservoirs, and most of these formations are mixed-wet or oil-wet and fractured, with extremely heterogeneous porosities and permeabilities. Implementation of enhanced oil recovery (EOR) techniques in this kind of reservoir is essential to achieve peak oil production and increase the recovery factor. Chemical EOR (CEOR) processes have been studied for many years in carbonate reservoirs but are not usually economically viable. Surfactant flooding has been considered as one of the most promising techniques among the chemical recovery methods due to the capacity of some surfactants to alter the carbonate rocks' wettability. However, the process is economically feasible only when losses of surfactant caused by adsorption into the porous media are decreased. Adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces. In general, the adsorption of cationic surfactants on carbonates is lower in comparison with other surfactants. Nevertheless, the high cost of cationic surfactants compared to anionic ones has led to studies aiming to evaluate the injection of the latter in the presence of a sacrificial agent in order to reduce the adsorption caused by interaction between the negative charges of the surfactant and positive charges on the carbonate surface. This work aims to study the effect of the presence of two chemicals, normally applied as scaling and corrosion inhibitors, on reducing the static adsorption of an anionic sodium olefin sulfonate surfactant on a carbonate rock. Water soluble poly(sodium methacrylate) (PSM) and diethanolamine (DEA) were evaluated as sacrificial agents in concentrations close to their scaling and corrosion inhibitor functions, respectively, to verify their sacrificial role in a co-injection chemical scenario. Adsorption studies were carried out using a pulverized carbonate rock in which low-salinity water was used as the base medium. Aqueous stability tests were carried out, which made it possible to select the correct salinity for the solutions of surfactant. Surface tension measurements were used as an indirect approach to study the adsorption of the surfactant in the presence and absence of PSM and DEA. Individually, PSM presented the best performance in reducing the adsorption of the anionic surfactant, while the DEA showed an almost null effect. However, when the chemicals were mixed, a synergistic effect was observed. The performance of PSM can probably be attributed to a steric effect of an adsorbed layer of polymer. It will be shown that even at lower concentrations, co-injection chemicals which are used for targeting other issues, such as scaling and corrosion inhibitors, may play the role of a sacrificial agent in reducing the adsorption of anionic surfactants, which is a concern in application to carbonate reservoirs.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84883935","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. Hanafy, H. Nasr-El-Din, Ahmed I. Rabie, Jian Zhou
Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system. This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface. The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested. This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both
{"title":"Effect of Corrosion–Inhibitor Chemistry on the Viscosity and Corrosion Rate of VES-Based Acids","authors":"A. Hanafy, H. Nasr-El-Din, Ahmed I. Rabie, Jian Zhou","doi":"10.2118/193574-MS","DOIUrl":"https://doi.org/10.2118/193574-MS","url":null,"abstract":"\u0000 Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.\u0000 This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.\u0000 The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.\u0000 This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75260263","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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