Gas reservoirs contain substantial amounts of natural gas and, in some cases, associated high API liquid hydrocarbons. Condensation of heavy hydrocarbons, especially in the area closer to the wellbore, occurs as a direct result of the decline in reservoir pressure. This hydrocarbon condensate, and in some cases water, tends to accumulate in the pore space and form a liquid bank. This liquid bank will result in a reduction in gas relative permeability and overall reduction in the well's productivity. This paper illustrates the synthesis and utilization of surface modified silica nanoparticles to mitigate the liquid banking phenomenon in gas reservoirs. Silica nanoparticles (S-NPs), of different sizes, were synthesized using the Stöber process. The impact of the nanoparticle size and degree of functionalization with different hydrophobic and omniphobic groups on altering the rock wettability properties to mitigate liquid banking in gas reservoirs were studied. The S-NPs (of sizes between 50-400 nm) were functionalized with various linear and branched fluoroalkyl groups, terminal amine, and epoxy groups. The particle size of surface modified silica nanoparticles was determined using dynamic light scattering (DLS). The performance of the surface modified silica nanoparticles was evaluated through measuring surface charge, change in contact angle, and by performing core flow experiments at reservoir conditions. A glass slide dip coated with 135 nm surface modified silica nanoparticles solution derivatized with terminal amine and perfluoroalkyl group provided a contact angle of 120° and 83° with water and decane, respectively. The contact angle can be tailored by changing the amount of amine and perfluoroalkyl concentrations on the particle surfaces. A contact angle of around 90° indicates a nonwetting neutral surface that results in minimizing capillary pressure and enhancing mobility of both hydrocarbon and water liquid phases. Using core flow studies and by estimating the improvement in gas and liquid relative permeabilities, surface modified silica nanoparticles treatment demonstrated a comparable performance to commercially available solutions at 1/5 the treatment volume. The surface modified silica nanoparticles sustained its performance indicating a stable and permanent coating on the rock surface. The silica nanoparticles functionalized with fluoroalkyl group, terminal amine and epoxy can be directly pumped without the need for a pretreatment of the rock surface. This results in less complexity when it comes to the field operation. The dual- functionalized silica nanoparticles were found to be effective in changing the rock surface wettability to neutral or nonwetting, thereby providing a potential solution to liquid banking problem in gas reservoirs.
{"title":"Nano-Texturing of Hydrocarbon Reservoirs with Omniphobic Nanoparticles to Mitigate Liquid Phase Trapping","authors":"M. Sayed, R. Saini, Hooisweng Ow","doi":"10.2118/204289-ms","DOIUrl":"https://doi.org/10.2118/204289-ms","url":null,"abstract":"\u0000 Gas reservoirs contain substantial amounts of natural gas and, in some cases, associated high API liquid hydrocarbons. Condensation of heavy hydrocarbons, especially in the area closer to the wellbore, occurs as a direct result of the decline in reservoir pressure. This hydrocarbon condensate, and in some cases water, tends to accumulate in the pore space and form a liquid bank. This liquid bank will result in a reduction in gas relative permeability and overall reduction in the well's productivity. This paper illustrates the synthesis and utilization of surface modified silica nanoparticles to mitigate the liquid banking phenomenon in gas reservoirs.\u0000 Silica nanoparticles (S-NPs), of different sizes, were synthesized using the Stöber process. The impact of the nanoparticle size and degree of functionalization with different hydrophobic and omniphobic groups on altering the rock wettability properties to mitigate liquid banking in gas reservoirs were studied. The S-NPs (of sizes between 50-400 nm) were functionalized with various linear and branched fluoroalkyl groups, terminal amine, and epoxy groups. The particle size of surface modified silica nanoparticles was determined using dynamic light scattering (DLS). The performance of the surface modified silica nanoparticles was evaluated through measuring surface charge, change in contact angle, and by performing core flow experiments at reservoir conditions.\u0000 A glass slide dip coated with 135 nm surface modified silica nanoparticles solution derivatized with terminal amine and perfluoroalkyl group provided a contact angle of 120° and 83° with water and decane, respectively. The contact angle can be tailored by changing the amount of amine and perfluoroalkyl concentrations on the particle surfaces. A contact angle of around 90° indicates a nonwetting neutral surface that results in minimizing capillary pressure and enhancing mobility of both hydrocarbon and water liquid phases. Using core flow studies and by estimating the improvement in gas and liquid relative permeabilities, surface modified silica nanoparticles treatment demonstrated a comparable performance to commercially available solutions at 1/5 the treatment volume. The surface modified silica nanoparticles sustained its performance indicating a stable and permanent coating on the rock surface.\u0000 The silica nanoparticles functionalized with fluoroalkyl group, terminal amine and epoxy can be directly pumped without the need for a pretreatment of the rock surface. This results in less complexity when it comes to the field operation. The dual- functionalized silica nanoparticles were found to be effective in changing the rock surface wettability to neutral or nonwetting, thereby providing a potential solution to liquid banking problem in gas reservoirs.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78231811","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}
Replacing oil from small pores of tight oil-wet rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, the liquid nanofluid has less adsorption loss during transport in the porous media, and can efficiently alter the rock wettability; meanwhile, it can also maintain a certain oil-water interfacial tension driving the water imbibition. In the previous study, the main properties of a Nonionic nanofluid-diluted microemulsion (DME) were evaluated, and the dispersion coefficient and adsorption rate of DME in tight rock under different conditions were quantified. In this study, to more intuitively show the change of wettability of DME to oil-wet rocks in the process of core flooding experiments and the changes of the water invasion front, CT is used to carry out on-line core flooding experiments, scan and calculate the water saturation in time, and compare it with the pressure drop in this process. Besides, the heterogeneity of rock samples is quantified in this paper. The results show that when the DME is used as the fracturing fluid additive, fingering of the water phase is observed at the beginning of the invasion; compared with brine, the fracturing fluid with DME has deeper invasion depth at the same time; the water invasion front gradually becomes uniform when the DME alters the rock wettability and triggers the imbibition; for tight rocks, DME can enter deeper pores and replace more oil because of its dominance. Finally, the selected nanofluids of DME were tested in two horizontal wells in the field, and their flowback fluids were collected and analyzed. The results show that the average droplet size of the flowback fluids in the wells using DME decreases with production time, and the altered wetting ability gradually returns to the level of the injected fracturing fluid. It can be confirmed that DME can migrate within the tight rock, make the rock surface more water-wet and enhance the imbibition capacity of the fracturing fluid, to reduce the reservoir pressure decline rate and increase production.
{"title":"Labortory and Pilot Tests of Enhanced Oil Recovery through Wettability Alteration by Diluted Microemulsions","authors":"Xurong Zhao, Tianbo Liang, Jin-Biao Zan, Mengchuang Zhang, Fu-jian Zhou, Xiongfei Liu","doi":"10.2118/204291-ms","DOIUrl":"https://doi.org/10.2118/204291-ms","url":null,"abstract":"\u0000 Replacing oil from small pores of tight oil-wet rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, the liquid nanofluid has less adsorption loss during transport in the porous media, and can efficiently alter the rock wettability; meanwhile, it can also maintain a certain oil-water interfacial tension driving the water imbibition. In the previous study, the main properties of a Nonionic nanofluid-diluted microemulsion (DME) were evaluated, and the dispersion coefficient and adsorption rate of DME in tight rock under different conditions were quantified.\u0000 In this study, to more intuitively show the change of wettability of DME to oil-wet rocks in the process of core flooding experiments and the changes of the water invasion front, CT is used to carry out on-line core flooding experiments, scan and calculate the water saturation in time, and compare it with the pressure drop in this process. Besides, the heterogeneity of rock samples is quantified in this paper. The results show that when the DME is used as the fracturing fluid additive, fingering of the water phase is observed at the beginning of the invasion; compared with brine, the fracturing fluid with DME has deeper invasion depth at the same time; the water invasion front gradually becomes uniform when the DME alters the rock wettability and triggers the imbibition; for tight rocks, DME can enter deeper pores and replace more oil because of its dominance. Finally, the selected nanofluids of DME were tested in two horizontal wells in the field, and their flowback fluids were collected and analyzed. The results show that the average droplet size of the flowback fluids in the wells using DME decreases with production time, and the altered wetting ability gradually returns to the level of the injected fracturing fluid. It can be confirmed that DME can migrate within the tight rock, make the rock surface more water-wet and enhance the imbibition capacity of the fracturing fluid, to reduce the reservoir pressure decline rate and increase production.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 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":"77625839","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}
Emulsifier concentration in SBM is an important factor of drilling fluid stability. Proper concentration of amidoamine emulsifier is imperative for controlling low fluid loss and maintaining emulsion stability. This study investigates the physical and chemical interactions between emulsifier and other additives and describes the processes by which emulsifier is depleted from the drilling fluid. Three main pathways of emulsifier consumption are identified: emulsifier adsorption on solids found in drilling fluids and low gravity solids (LGS), chemical degradation, and to stabilize the invert emulsion. Design of experiments model and analytical procedure based on 1H NMR (nuclear magnetic resonance) spectroscopy was used to quantify the required emulsifier concentration in Non-Aqueous Fluid system (NAF). Additionally, model systems were used to estimate the excess of emulsifier, evaluate the emulsifier losses due to alkaline hydrolysis at elevated temperature, and measure adsorption of emulsifier on barite and various LGS types. Calculations for emulsifier depletion based on model systems were correlated to performance of formulated drilling fluids for verification. Typical emulsifier requirement in high performance NAF is 8-12 pounds per barrel (ppb). Majority of the emulsifier is adsorbed on weighting agents (barite) and rheology modifiers (clays), which are used to formulate NAF, that contribute to their effective dispersion in the solution and control fluid rheology. The adsorption process is found to be sensitive to the emulsifier concentration, solids mineralogy, wetting agent and temperature. Analytical Langmuir-Freundlich isotherm was used to describe adsorption data and estimate the adsorption capacity of the system. The emulsifier degradation pathway is another important factor of emulsifier consumption; however, emulsifier degradation at 250°F is not significant. While NAF are generally run ‘rich’ to mitigate depletion and maintain fluid stability, adsorption onto minerals will become an issue especially at high LGS concentration. These results will be greatly beneficial in the further development of NAF drilling fluid formulations and will assist field engineers in understanding the effect excess emulsifier will have on the drilling fluid and enable them to more effectively control the fluid properties under variations in emulsifier and LGS concentration during drilling.
{"title":"Fate of Emulsifier in Invert Emulsion Drilling Fluids: Hydrolysis and Adsorption on Solids","authors":"Dimitri M. Khramov, E. Barmatov","doi":"10.2118/204290-ms","DOIUrl":"https://doi.org/10.2118/204290-ms","url":null,"abstract":"\u0000 Emulsifier concentration in SBM is an important factor of drilling fluid stability. Proper concentration of amidoamine emulsifier is imperative for controlling low fluid loss and maintaining emulsion stability. This study investigates the physical and chemical interactions between emulsifier and other additives and describes the processes by which emulsifier is depleted from the drilling fluid. Three main pathways of emulsifier consumption are identified: emulsifier adsorption on solids found in drilling fluids and low gravity solids (LGS), chemical degradation, and to stabilize the invert emulsion.\u0000 Design of experiments model and analytical procedure based on 1H NMR (nuclear magnetic resonance) spectroscopy was used to quantify the required emulsifier concentration in Non-Aqueous Fluid system (NAF). Additionally, model systems were used to estimate the excess of emulsifier, evaluate the emulsifier losses due to alkaline hydrolysis at elevated temperature, and measure adsorption of emulsifier on barite and various LGS types. Calculations for emulsifier depletion based on model systems were correlated to performance of formulated drilling fluids for verification.\u0000 Typical emulsifier requirement in high performance NAF is 8-12 pounds per barrel (ppb). Majority of the emulsifier is adsorbed on weighting agents (barite) and rheology modifiers (clays), which are used to formulate NAF, that contribute to their effective dispersion in the solution and control fluid rheology. The adsorption process is found to be sensitive to the emulsifier concentration, solids mineralogy, wetting agent and temperature. Analytical Langmuir-Freundlich isotherm was used to describe adsorption data and estimate the adsorption capacity of the system. The emulsifier degradation pathway is another important factor of emulsifier consumption; however, emulsifier degradation at 250°F is not significant. While NAF are generally run ‘rich’ to mitigate depletion and maintain fluid stability, adsorption onto minerals will become an issue especially at high LGS concentration.\u0000 These results will be greatly beneficial in the further development of NAF drilling fluid formulations and will assist field engineers in understanding the effect excess emulsifier will have on the drilling fluid and enable them to more effectively control the fluid properties under variations in emulsifier and LGS concentration during drilling.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79548984","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-017
M. S. Islam
{"title":"Chemical Shifts and EXAFS of the Lm Absorption Discontinuity of Dysprosium in Some of Its Compounds","authors":"M. S. Islam","doi":"10.1515/9783112495445-017","DOIUrl":"https://doi.org/10.1515/9783112495445-017","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75168169","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-040
N. Lawerence, T. M. Haridasan
{"title":"Mean Square Amplitude of Transition Metal Dichalcogenide lT-TiSe^ in the Normal and Commensurate Charge Density Wave Phases","authors":"N. Lawerence, T. M. Haridasan","doi":"10.1515/9783112495445-040","DOIUrl":"https://doi.org/10.1515/9783112495445-040","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87526204","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-023
L. I. Magarill, S. Savvinykh
{"title":"Dynamic Conductivity Singularities of a Many-Valley Semiconductor in a Quantizing Magnetic Field","authors":"L. I. Magarill, S. Savvinykh","doi":"10.1515/9783112495445-023","DOIUrl":"https://doi.org/10.1515/9783112495445-023","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83999736","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-009
M. Czapelski, M. Suszyńska
{"title":"Effect of Plastic Deformation upon Optical Absorption of KCl:Eu 2+ Crystals","authors":"M. Czapelski, M. Suszyńska","doi":"10.1515/9783112495445-009","DOIUrl":"https://doi.org/10.1515/9783112495445-009","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83761614","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-044
T. Tsuboi
{"title":"Formation of the Tl°(1) Center in KC1","authors":"T. Tsuboi","doi":"10.1515/9783112495445-044","DOIUrl":"https://doi.org/10.1515/9783112495445-044","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74308171","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 1985-12-31DOI: 10.1515/9783112495445-016
E. Popov, M. M. Kotlyakskii, I. Edelman
{"title":"Temperature and Field Dependence of Exciton-Magnon Absorption of NaMnCl3","authors":"E. Popov, M. M. Kotlyakskii, I. Edelman","doi":"10.1515/9783112495445-016","DOIUrl":"https://doi.org/10.1515/9783112495445-016","url":null,"abstract":"","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1985-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90341168","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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