The necessity to verify epoxy resin sealant's reliability for well applications is amplified as its use increases. Limited data exists to confirm resin's long-term durability or chemical stability under exposure to well fluids at temperature and pressure. This paper presents laboratory results illustrating durability and stability of epoxy resin exposed to a range of well fluids over a span of temperatures. Additionally, results of accelerated thermal degradation testing further quantify long-term thermal and chemical stability. Epoxy resins formulated for a range of remedial and abandonment applications were cured in fresh water, CaCl2 brine, and hydrocarbon at 170°F up to one year. Additional samples cured in fresh water and water containing CO2 and H2S at elevated temperatures (220°F to 320°F) for up to six weeks to produce accelerated degradation reactions allowed the assessment of resin degradation verses temperature. Thermal Gravimetric Analysis (TGA) evaluated chemical and mechanical degradation verses time at temperatures ranging from 200°C to 400°C. Arrhenius calculations were performed to forecast long term stability of resins across their intended temperature ranges. Resulting data were analyzed to develop an inclusive assessment of resin stability and durability in well environments. Results indicate properly formulated epoxy resin is a mechanically, chemically, and thermally durable sealant for well applications.
{"title":"Epoxy Resin Exhibits Long-Term Durability and Chemical Stability as a Well Sealant","authors":"F. Sabins, A. Apblett, R. Shafer, L. Watters","doi":"10.2118/204374-ms","DOIUrl":"https://doi.org/10.2118/204374-ms","url":null,"abstract":"\u0000 The necessity to verify epoxy resin sealant's reliability for well applications is amplified as its use increases. Limited data exists to confirm resin's long-term durability or chemical stability under exposure to well fluids at temperature and pressure. This paper presents laboratory results illustrating durability and stability of epoxy resin exposed to a range of well fluids over a span of temperatures. Additionally, results of accelerated thermal degradation testing further quantify long-term thermal and chemical stability. Epoxy resins formulated for a range of remedial and abandonment applications were cured in fresh water, CaCl2 brine, and hydrocarbon at 170°F up to one year. Additional samples cured in fresh water and water containing CO2 and H2S at elevated temperatures (220°F to 320°F) for up to six weeks to produce accelerated degradation reactions allowed the assessment of resin degradation verses temperature. Thermal Gravimetric Analysis (TGA) evaluated chemical and mechanical degradation verses time at temperatures ranging from 200°C to 400°C. Arrhenius calculations were performed to forecast long term stability of resins across their intended temperature ranges. Resulting data were analyzed to develop an inclusive assessment of resin stability and durability in well environments. Results indicate properly formulated epoxy resin is a mechanically, chemically, and thermally durable sealant for well applications.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84510227","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 catastrophic events faced by the Oil and Gas industry in the past depict the importance of maintaining the integrity of the well. The cement acts as a crucial barrier throughout the life cycle of the well. The contamination of the cement occurs due to inefficiency in cementing practices and operations. Experimental investigations have been done on the reduction in mechanical properties of different API class cement considering contamination with water-based mud and oil-based mud. This study focuses on analyzing the changes in mechanical properties of API Class C cement on varying the following parameters: OBM contamination (0%, 0.6%, 1.1%, 2.2%, 4.3%) Curing time (4 hrs, 6 hrs, 8 hrs, 1 day, 3 days, 7 days) Temperature (25˚C, 75 ˚C) API recommendations were followed for preparing the cement slurries. The destructive, as well as non-destructive tests were carried out on the cement samples at ambient room temperature to measure the uniaxial compressive strength (UCS) for OBM contaminated class C cement slurries. The general trend observed is that the UCS increases with an increase in curing time and temperature. UCS decreases with an increase in OBM contamination. Logarithmic trends were obtained for UCS vs curing time for different contaminations at a given temperature. Exceptions were observed at lower curing times where contaminated samples showed better results than the neat cement slurries. These observations play a critical role in understanding contaminated cement behavior. This widespread work was carried out only on API Class C cement to provide reliable data for future references. The correlations presented in this paper will help operators estimate the deterioration in mechanical properties of Class C cement in the presence of low OBM contamination. Email: nachiket.arbad@ou.edu & cteodoriu@ou.edu
{"title":"Mechanical Properties of API Class C Cement Contaminated with Oil-Based Mud OBM at Elevated Temperatures and Early Curing Time","authors":"Nachiket Arbad, F. Rincón, C. Teodoriu, M. Amani","doi":"10.2118/204302-ms","DOIUrl":"https://doi.org/10.2118/204302-ms","url":null,"abstract":"\u0000 The catastrophic events faced by the Oil and Gas industry in the past depict the importance of maintaining the integrity of the well. The cement acts as a crucial barrier throughout the life cycle of the well. The contamination of the cement occurs due to inefficiency in cementing practices and operations. Experimental investigations have been done on the reduction in mechanical properties of different API class cement considering contamination with water-based mud and oil-based mud.\u0000 This study focuses on analyzing the changes in mechanical properties of API Class C cement on varying the following parameters:\u0000 OBM contamination (0%, 0.6%, 1.1%, 2.2%, 4.3%) Curing time (4 hrs, 6 hrs, 8 hrs, 1 day, 3 days, 7 days) Temperature (25˚C, 75 ˚C)\u0000 API recommendations were followed for preparing the cement slurries. The destructive, as well as non-destructive tests were carried out on the cement samples at ambient room temperature to measure the uniaxial compressive strength (UCS) for OBM contaminated class C cement slurries.\u0000 The general trend observed is that the UCS increases with an increase in curing time and temperature. UCS decreases with an increase in OBM contamination. Logarithmic trends were obtained for UCS vs curing time for different contaminations at a given temperature. Exceptions were observed at lower curing times where contaminated samples showed better results than the neat cement slurries. These observations play a critical role in understanding contaminated cement behavior.\u0000 This widespread work was carried out only on API Class C cement to provide reliable data for future references. The correlations presented in this paper will help operators estimate the deterioration in mechanical properties of Class C cement in the presence of low OBM contamination.\u0000 Email: nachiket.arbad@ou.edu & cteodoriu@ou.edu","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82773619","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}
Justin Montgomery, T. McNally, Jay Hunger, S. Subramanian
The retardation of class H Portland cement using lignosulfonates was investigated in the temperature range between 54°C and 153°C. Lignosulfonates with varying extent of modification was used in the study, and the optimum retarder dosage and temperature range to achieve desired thickening time was identified for different lignosulfonate types (non-modified, modified and highly modified). In general, a linear thickening response was observed at low retarder dosage, while a near exponential increase in thickening time response was observed at higher dosages. Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry. A significant finding is that the thickening time responses trend from near linear at low dosages, transitioning to near exponential at higher dosages. The observed results varied depending on the extent of modification performed on the lignosulfonate retarder. Pure lignosulfonate retarders produce optimal dosage response from 54°C to 97°C. Modified retarders work best in the range of 97°C to 118°C. While highly modified retarders perform best in the range of 118°C to 153°C. Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry.
{"title":"Evaluation of Lignosulfonate Based Retarders for Thickening Time as a Function of Dosage and Temperature","authors":"Justin Montgomery, T. McNally, Jay Hunger, S. Subramanian","doi":"10.2118/204327-ms","DOIUrl":"https://doi.org/10.2118/204327-ms","url":null,"abstract":"\u0000 The retardation of class H Portland cement using lignosulfonates was investigated in the temperature range between 54°C and 153°C. Lignosulfonates with varying extent of modification was used in the study, and the optimum retarder dosage and temperature range to achieve desired thickening time was identified for different lignosulfonate types (non-modified, modified and highly modified). In general, a linear thickening response was observed at low retarder dosage, while a near exponential increase in thickening time response was observed at higher dosages.\u0000 Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry. A significant finding is that the thickening time responses trend from near linear at low dosages, transitioning to near exponential at higher dosages. The observed results varied depending on the extent of modification performed on the lignosulfonate retarder.\u0000 Pure lignosulfonate retarders produce optimal dosage response from 54°C to 97°C. Modified retarders work best in the range of 97°C to 118°C. While highly modified retarders perform best in the range of 118°C to 153°C. Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79221820","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}
Linping Ke, Josselyne Chano, Melissa C. Weston, Hong Sun, Dong Shen
Currently, well stimulation in North America has evolved almost entirely to slickwater fracturing with friction reducers (FRs). Some parts of North America are notorious for their poor water quality, so wells are commonly treated using high total dissolved solids (TDS)-containing flow-back or produced water. Cationic FRs are usually applied in these systems due to their tolerance to multivalent cations in such waters. Additionally, dry friction reducers have gained momentum for better economics and logistics. In this paper, a dry cationic FR is systematically studied with respect to its "on the fly" hydration capability, friction reduction, mechanical stability, compatibility with other anionic chemical additives, and thermal stability in different levels of TDS brines. The cationic FR solution was subjected to varying shearing rates to understand its hydration capability, friction reduction, and mechanical stability. Its compatibility with anionic additives, such as a scale inhibitor, was also tested in a laboratory friction loop. Thermal stability of the cationic FR solution was studied at 150°F using a viscometer and Multi-Angle Laser Light Scattering (MALLS) method to obtain molecular weight information. The charge characteristics of the cationic FR, indicative of self-degradation properties, with exposure to heat, were also studied. Potential formation damage of the FR solution was evaluated with core flow tests in the absence of oxidizing breakers. Friction reduction and hydration tests show that the FR performs well in high TDS waters, even at low temperature, reaching its peak performance rapidly. The cationic FR possesses high mechanical stability even after being exposed to high pumping rates in the friction loop. It is well known that cationic FRs are not compatible with polyanionic scale inhibitors; in this study, a compatible scale inhibitor, SI-1, is identified. Additionally, there has historically been hesitation to use such cationic materials due to concerns of formation compatibility with negatively charged source rocks or flocculation in water treatment plants. Thermal testing with cationic FRs reveals that the material degrades to anionic without the aid of any other additive, which is confirmed by the fact that addition of polycationic additive, C1, caused coacervation in the heat-treated sample. As a result, concerns over effects of rock wettability or incompatibility with water treatment additives can be alleviated. No anionic FRs undergo similar change of the ionic charge. Thermal testing with cationic FR solutions also shows a significant viscosity drop, surprisingly without pronounced molecular weight loss (via MALLS). However, core flow testing of cationic FR fluids shows good regained permeability, even without breakers, further confirming self-cleaning capability. The degradation mechanism of these FRs will be shown. The self-cleaning capability of the dry cationic FR, even at relatively low bottomhole temperature
{"title":"Dry Cationic Friction Reducers: New Alternative for High TDS Slickwater","authors":"Linping Ke, Josselyne Chano, Melissa C. Weston, Hong Sun, Dong Shen","doi":"10.2118/204286-ms","DOIUrl":"https://doi.org/10.2118/204286-ms","url":null,"abstract":"\u0000 Currently, well stimulation in North America has evolved almost entirely to slickwater fracturing with friction reducers (FRs). Some parts of North America are notorious for their poor water quality, so wells are commonly treated using high total dissolved solids (TDS)-containing flow-back or produced water. Cationic FRs are usually applied in these systems due to their tolerance to multivalent cations in such waters. Additionally, dry friction reducers have gained momentum for better economics and logistics. In this paper, a dry cationic FR is systematically studied with respect to its \"on the fly\" hydration capability, friction reduction, mechanical stability, compatibility with other anionic chemical additives, and thermal stability in different levels of TDS brines.\u0000 The cationic FR solution was subjected to varying shearing rates to understand its hydration capability, friction reduction, and mechanical stability. Its compatibility with anionic additives, such as a scale inhibitor, was also tested in a laboratory friction loop. Thermal stability of the cationic FR solution was studied at 150°F using a viscometer and Multi-Angle Laser Light Scattering (MALLS) method to obtain molecular weight information. The charge characteristics of the cationic FR, indicative of self-degradation properties, with exposure to heat, were also studied. Potential formation damage of the FR solution was evaluated with core flow tests in the absence of oxidizing breakers.\u0000 Friction reduction and hydration tests show that the FR performs well in high TDS waters, even at low temperature, reaching its peak performance rapidly. The cationic FR possesses high mechanical stability even after being exposed to high pumping rates in the friction loop. It is well known that cationic FRs are not compatible with polyanionic scale inhibitors; in this study, a compatible scale inhibitor, SI-1, is identified. Additionally, there has historically been hesitation to use such cationic materials due to concerns of formation compatibility with negatively charged source rocks or flocculation in water treatment plants. Thermal testing with cationic FRs reveals that the material degrades to anionic without the aid of any other additive, which is confirmed by the fact that addition of polycationic additive, C1, caused coacervation in the heat-treated sample. As a result, concerns over effects of rock wettability or incompatibility with water treatment additives can be alleviated. No anionic FRs undergo similar change of the ionic charge. Thermal testing with cationic FR solutions also shows a significant viscosity drop, surprisingly without pronounced molecular weight loss (via MALLS). However, core flow testing of cationic FR fluids shows good regained permeability, even without breakers, further confirming self-cleaning capability. The degradation mechanism of these FRs will be shown.\u0000 The self-cleaning capability of the dry cationic FR, even at relatively low bottomhole temperature","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72611414","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}
C. Aften, Yaser Asgari, Lee Bailey, Gene Middleton, F. Muhammed, Parasmani Pageni, Keith Sullivan
Friction reducer evaluations for field application selection are conducted in laboratory benchtop recirculating flow loops or once-through systems. Industry standard procedures and benchtop flow loop (loop) system specifications for friction reduction assessment are nonexistent, though standardization efforts are recently documented. Research and papers correlating friction reducer performance to brine and additives have been published, however other key variables can significantly affect performance and therefore must be addressed to maximize product recommendation accuracy. This paper illustrates how variances affect results. Benchtop recirculating loops used for testing friction reduction products for a specific field's application vary significantly in system components, configurations, and test analyses. Crucial loop system variance examples include differing pipe diameters, pump configurations, flow meter types and placement, differential pressure section and full run lengths, reservoir designs, mixing conditions, and end performance calculations. Oil and gas producers and service companies are trending towards outsourcing friction reducers to independent testing laboratories for loop assessment results prior to recommending friction reducers for end use field applications. These recommendations may have inherent selection bias depending upon the loop system's components and configuration. Friction reduction calculations during loop testing do not consistently consider changes in viscosity and temperature, thereby altering absolute results when evaluating performance. To apply the simplified assumptions in standard pressure, drop methodology, equivalency in flow rate, density, viscosity, and temperature within the run must be maintained. Performance of the friction reducer in a specific brine and additive test run should primarily be dependent upon dosage and method of injecting friction reducer into the loop, however other variables can contribute to performance results. We presume equivalency in pipe roughness and proper loop cleansing. The effects of these variables on friction reduction response applying wide-ranging factors of flowrate, density, viscosity, and temperature are evaluated using designed experiments with responses plotted and illustrated in Cartesian and contour graphs. The result of these designed experiments identified that certain variables are more influential on friction reducers’ measured performances in standard loop experiments and require observation and documentation during performance testing. The final study in this work generated vastly different performance curves when all of the aspects of loop design, entry and differential run lengths, flow rate, injection method, friction reducer types and loadings, and brine types, densities, viscosities, and temperatures were held constant. The goal of benchtop loop testing is scaling for actual field applications. Scaling discrepancies persist however due to diffe
{"title":"Critical Examination of Variables Effecting Friction Loop Results for Friction Reducer Selection","authors":"C. Aften, Yaser Asgari, Lee Bailey, Gene Middleton, F. Muhammed, Parasmani Pageni, Keith Sullivan","doi":"10.2118/204280-ms","DOIUrl":"https://doi.org/10.2118/204280-ms","url":null,"abstract":"\u0000 Friction reducer evaluations for field application selection are conducted in laboratory benchtop recirculating flow loops or once-through systems. Industry standard procedures and benchtop flow loop (loop) system specifications for friction reduction assessment are nonexistent, though standardization efforts are recently documented. Research and papers correlating friction reducer performance to brine and additives have been published, however other key variables can significantly affect performance and therefore must be addressed to maximize product recommendation accuracy. This paper illustrates how variances affect results.\u0000 Benchtop recirculating loops used for testing friction reduction products for a specific field's application vary significantly in system components, configurations, and test analyses. Crucial loop system variance examples include differing pipe diameters, pump configurations, flow meter types and placement, differential pressure section and full run lengths, reservoir designs, mixing conditions, and end performance calculations. Oil and gas producers and service companies are trending towards outsourcing friction reducers to independent testing laboratories for loop assessment results prior to recommending friction reducers for end use field applications. These recommendations may have inherent selection bias depending upon the loop system's components and configuration. Friction reduction calculations during loop testing do not consistently consider changes in viscosity and temperature, thereby altering absolute results when evaluating performance. To apply the simplified assumptions in standard pressure, drop methodology, equivalency in flow rate, density, viscosity, and temperature within the run must be maintained. Performance of the friction reducer in a specific brine and additive test run should primarily be dependent upon dosage and method of injecting friction reducer into the loop, however other variables can contribute to performance results. We presume equivalency in pipe roughness and proper loop cleansing.\u0000 The effects of these variables on friction reduction response applying wide-ranging factors of flowrate, density, viscosity, and temperature are evaluated using designed experiments with responses plotted and illustrated in Cartesian and contour graphs. The result of these designed experiments identified that certain variables are more influential on friction reducers’ measured performances in standard loop experiments and require observation and documentation during performance testing. The final study in this work generated vastly different performance curves when all of the aspects of loop design, entry and differential run lengths, flow rate, injection method, friction reducer types and loadings, and brine types, densities, viscosities, and temperatures were held constant.\u0000 The goal of benchtop loop testing is scaling for actual field applications. Scaling discrepancies persist however due to diffe","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84856385","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 efficiency of CO2 water-alternating-gas (WAG) flooding is highly limited in low-permeability heavy oil reservoirs due to the viscosifying action of W/O emulsification and high mobility contrast between oil and CO2. Here we propose a new enhanced oil recovery (EOR) process which involves water-based nanofluid-alternating-CO2 (NWAG) injection, and investigate the synergistic effect of nanofluid and CO2 for enhancing heavy oil recovery. Firstly, the oil-nanofluid and oil-water emulsions were prepared, and the bulk rheology and interfacial properties of emulsion fluid were tested. Then, core flooding tests were conducted to examine the NWAG flooding efficiency and its underlying mechanisms. The results showed that the bulk viscosity and viscoelasticity of oil-nanofluid emulsion reported much lower than those of oil-water emulsion, and nanofluid presented a positive contribution to the phase inversion from W/O to O/W emulsification. Compared with oil-water emulsion, the interfacial storage modulus of oil-nanofluid emulsion was obviously increased, which confirmed that more of crude oil heavy components with surface activity (e.g., resin and asphaltene) were adsorbed on interfacial film with the addition of silica nanoparticles (NPs). However, the interfacial viscosity of oil-nanofluid emulsion was much lower than that of oil-water emulsion, showing the irregularity of interfacial adsorption. This implied that the self-assembly structure of crude oil heavy component of the oil-water interface was destroyed due to the surface activity of silica NPs. During the core flooding experiments, NWAG injection could reduce the displacement pressure by 57.14% and increase oil recovery by 23.31% compared to WAG injection. By comparing produced-oil components after WAG and NWAG injection, we found that more of crude oil light components were extracted by CO2 during NWAG flooding, showing that the interaction between CO2 and crude oil was improved after oil-nanofluid emulsification. These findings clearly indicated two main EOR mechanisms of NWAG injection. One was the phase inversion during the nanofluid flooding process. The addition of silica NPs promoted phase-inversion emulsification and thus improved the displacement efficiency. The other was the enhanced interaction between CO2 and crude oil after oil-nanofluid emulsification. Because of the enhanced adsorption of crude oil heavy component on the oil-water interface, the proportion of light hydrocarbon increased in the bulk phase, and so the interaction between CO2 and oil phase was improved. This work could provide a new insight into the high-efficiency exploitation of low-permeability heavy oil reservoirs.
{"title":"Water-Based Nanofluid-Alternating-CO2 Injection for Enhancing Heavy Oil Recovery: Underlying Mechanisms that Influence its Efficiency","authors":"Changxiao Cao, Zhaojie Song, Shan Su, Zihan Tang, Zehui Xie, Xuya Chang","doi":"10.2118/204331-ms","DOIUrl":"https://doi.org/10.2118/204331-ms","url":null,"abstract":"\u0000 The efficiency of CO2 water-alternating-gas (WAG) flooding is highly limited in low-permeability heavy oil reservoirs due to the viscosifying action of W/O emulsification and high mobility contrast between oil and CO2. Here we propose a new enhanced oil recovery (EOR) process which involves water-based nanofluid-alternating-CO2 (NWAG) injection, and investigate the synergistic effect of nanofluid and CO2 for enhancing heavy oil recovery. Firstly, the oil-nanofluid and oil-water emulsions were prepared, and the bulk rheology and interfacial properties of emulsion fluid were tested. Then, core flooding tests were conducted to examine the NWAG flooding efficiency and its underlying mechanisms. The results showed that the bulk viscosity and viscoelasticity of oil-nanofluid emulsion reported much lower than those of oil-water emulsion, and nanofluid presented a positive contribution to the phase inversion from W/O to O/W emulsification. Compared with oil-water emulsion, the interfacial storage modulus of oil-nanofluid emulsion was obviously increased, which confirmed that more of crude oil heavy components with surface activity (e.g., resin and asphaltene) were adsorbed on interfacial film with the addition of silica nanoparticles (NPs). However, the interfacial viscosity of oil-nanofluid emulsion was much lower than that of oil-water emulsion, showing the irregularity of interfacial adsorption. This implied that the self-assembly structure of crude oil heavy component of the oil-water interface was destroyed due to the surface activity of silica NPs. During the core flooding experiments, NWAG injection could reduce the displacement pressure by 57.14% and increase oil recovery by 23.31% compared to WAG injection. By comparing produced-oil components after WAG and NWAG injection, we found that more of crude oil light components were extracted by CO2 during NWAG flooding, showing that the interaction between CO2 and crude oil was improved after oil-nanofluid emulsification. These findings clearly indicated two main EOR mechanisms of NWAG injection. One was the phase inversion during the nanofluid flooding process. The addition of silica NPs promoted phase-inversion emulsification and thus improved the displacement efficiency. The other was the enhanced interaction between CO2 and crude oil after oil-nanofluid emulsification. Because of the enhanced adsorption of crude oil heavy component on the oil-water interface, the proportion of light hydrocarbon increased in the bulk phase, and so the interaction between CO2 and oil phase was improved. This work could provide a new insight into the high-efficiency exploitation of low-permeability heavy oil reservoirs.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"42 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":"86851300","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}
B. Wei, Runxue Mao, Haoran Tang, Lele Wang, Dianlin Wang, Yiwen Wang, Junyu You, Jun Lu
Spontaneous imbibition (SI) is an essential method for accelerating mass exchange between fracture and matrix in tight oil reservoirs. However, conventional systems such as brine and surfactant solution have limited imbibition effects, so there is still abundant remaining oil in the matrix. Nanoemulsion holds the most promising potential in improving tight oil recovery owing to the favorable surface activity and nanoscale droplets, but it still lacks economic and facile methods to fabricate nanoemulsions. Therefore, in this paper, we prepared a kind of O/W nanoemulsion of catanionic surfactants with a low dosage of surfactant and energy consumption, which was then used to assess spontaneous imbibition performance in Changqing outcrop cores by experimental and numerical simulation. We have fully considered the possible imbibition mechanisms of nanoemulsion including wettability alteration, IFT reduction, solubilization and emulsification, etc., and successfully applied to the nanoemulsion imbibition model. The model and experimental data were found to be in good agreement. The results showed that the imbibition rate and oil recovery factor of the nanoemulsion in the first 100 hours are lower than that of brine. In the late stage, we observed a longer equilibrium time and a faster and higher oil imbibition process in nanoemulsion with ultralow IFT. Finally, we confirmed that solubilization and emulsification is one of the domiant mechanisms for nanoemulsion imbibition by comparing with the modelling without considering solubilization and emulsification.
{"title":"Facile Fabrication of Nanoemulsions through the Efficient Catanionic Surfactants for Spontaneous Imbibition in Tight Oil Reservoirs: Experimental and Numerical Simulation","authors":"B. Wei, Runxue Mao, Haoran Tang, Lele Wang, Dianlin Wang, Yiwen Wang, Junyu You, Jun Lu","doi":"10.2118/204336-ms","DOIUrl":"https://doi.org/10.2118/204336-ms","url":null,"abstract":"\u0000 Spontaneous imbibition (SI) is an essential method for accelerating mass exchange between fracture and matrix in tight oil reservoirs. However, conventional systems such as brine and surfactant solution have limited imbibition effects, so there is still abundant remaining oil in the matrix. Nanoemulsion holds the most promising potential in improving tight oil recovery owing to the favorable surface activity and nanoscale droplets, but it still lacks economic and facile methods to fabricate nanoemulsions. Therefore, in this paper, we prepared a kind of O/W nanoemulsion of catanionic surfactants with a low dosage of surfactant and energy consumption, which was then used to assess spontaneous imbibition performance in Changqing outcrop cores by experimental and numerical simulation. We have fully considered the possible imbibition mechanisms of nanoemulsion including wettability alteration, IFT reduction, solubilization and emulsification, etc., and successfully applied to the nanoemulsion imbibition model. The model and experimental data were found to be in good agreement. The results showed that the imbibition rate and oil recovery factor of the nanoemulsion in the first 100 hours are lower than that of brine. In the late stage, we observed a longer equilibrium time and a faster and higher oil imbibition process in nanoemulsion with ultralow IFT. Finally, we confirmed that solubilization and emulsification is one of the domiant mechanisms for nanoemulsion imbibition by comparing with the modelling without considering solubilization and emulsification.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"85 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89533876","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：