Chunli Li, Zhiwei Yue, Xiao-ying Tian, John Hazlewood
Humic acids, one major type of organic foulants in steam assisted gravity drainage (SAGD) produced water, can precipitate on surface and downhole equipment in SAGD facilities, resulting in high cleaning costs, potential equipment damage and decrease of injectivity of disposal wells. In this paper, a cost-effective chemical solution is presented where an alcohol ethoxylate surfactant/chelating agent package can efficiently disperse the organic fouling molecules in SAGD produced water; therefore, the approach is expected to significantly mitigate the humic acid related fouling issues in the SAGD system. In this study, a variety of commercially available surfactant products were evaluated for their aids in well injectivity on humic acid molecules in the freshly obtained SAGD produced water. The lab testing filtration apparatus was specially designed to simulate the sandstone formation geology of SAGD disposal wells. An "efficiency factor" was defined to grade the dispersing performance of the surfactant and/or surfactant/chelating agent package in the lab filtration tests. The efficiency factor provides a reasonable estimation regarding how well the chemical can reduce the plugging risk in a disposal well as compared to the untreated produced water. Among all the surfactant products tested, an alcohol ethoxylate surfactant with the appropriate molecular structure shows distinguished dispersing performance on humic acids in SAGD produced water. However, the surfactant alone was found inconsistent in the dispersing performance when different batches of the produced water were involved. Inclusion of the specific metal chelating agents to the above surfactant formulation improved the dispersing performance consistency. The chelator molecules presumably help destroy the intermolecular bridges among humic acid molecules in the SAGD produced water; thereby, increasing the dispersing effectiveness of the alcohol ethyoxylate surfactants. Tests show that the efficiency factor of the surfactant/chelating agent package is higher than 8, which implies that the formulation could lead to eight times extension of the interval between workovers on SAGD disposal wells, a significant reduction for the operational downtime and costs. This study presented a cost-effective chemical solution to help disperse the humic acid molecules in SAGD produced water, which can help significantly reduce the fouling risk caused by organic foulants, improve injectivity and extend the intervals between workovers of SAGD disposal wells.
{"title":"Effective Treatment of Humic Acid Foulants in SAGD Produced Water","authors":"Chunli Li, Zhiwei Yue, Xiao-ying Tian, John Hazlewood","doi":"10.2118/204368-ms","DOIUrl":"https://doi.org/10.2118/204368-ms","url":null,"abstract":"\u0000 Humic acids, one major type of organic foulants in steam assisted gravity drainage (SAGD) produced water, can precipitate on surface and downhole equipment in SAGD facilities, resulting in high cleaning costs, potential equipment damage and decrease of injectivity of disposal wells. In this paper, a cost-effective chemical solution is presented where an alcohol ethoxylate surfactant/chelating agent package can efficiently disperse the organic fouling molecules in SAGD produced water; therefore, the approach is expected to significantly mitigate the humic acid related fouling issues in the SAGD system.\u0000 In this study, a variety of commercially available surfactant products were evaluated for their aids in well injectivity on humic acid molecules in the freshly obtained SAGD produced water. The lab testing filtration apparatus was specially designed to simulate the sandstone formation geology of SAGD disposal wells. An \"efficiency factor\" was defined to grade the dispersing performance of the surfactant and/or surfactant/chelating agent package in the lab filtration tests. The efficiency factor provides a reasonable estimation regarding how well the chemical can reduce the plugging risk in a disposal well as compared to the untreated produced water.\u0000 Among all the surfactant products tested, an alcohol ethoxylate surfactant with the appropriate molecular structure shows distinguished dispersing performance on humic acids in SAGD produced water. However, the surfactant alone was found inconsistent in the dispersing performance when different batches of the produced water were involved. Inclusion of the specific metal chelating agents to the above surfactant formulation improved the dispersing performance consistency. The chelator molecules presumably help destroy the intermolecular bridges among humic acid molecules in the SAGD produced water; thereby, increasing the dispersing effectiveness of the alcohol ethyoxylate surfactants. Tests show that the efficiency factor of the surfactant/chelating agent package is higher than 8, which implies that the formulation could lead to eight times extension of the interval between workovers on SAGD disposal wells, a significant reduction for the operational downtime and costs.\u0000 This study presented a cost-effective chemical solution to help disperse the humic acid molecules in SAGD produced water, which can help significantly reduce the fouling risk caused by organic foulants, improve injectivity and extend the intervals between workovers of SAGD disposal wells.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79695578","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In recent years, ASP flooding has been widely applied and obtained the remarkable effect. During the ASP flooding process, the oil composition has a great effect on the interfacial tension, which plays a vital role in the oil displacement effect. However, through literature research, few have made a profound study on the effect of oil composition on the recover rate. As a result, it is very important to carry out relevant research. For the oil sample (I) and sample (II) from two different regions in DQ, the crude oil composition analysis is first carried out. After the mixing of oil system and ASP system, the distribution ratio of agent is obtained. Furthermore, the oil composition does have an impact on the interfacial tension and recovery rate, and its influence law is explored. Finally, its application is introduced and analyzed. Research results show that, compare with sample (II), the sample (I) has more heavy components. After the mixing of oil samples and ASP, more surfactant and alkali enters into the oil phase of sample (I). Therefore, based on the similar miscibility principle, the surfactant is more likely to leave the oil water interface and enter into the oil phase of sample (I), which has a negative effect on reducing the interfacial tension. Furthermore, the phenomenon of chromatographic separation aggravates the adsorption of surfactant on rock surface. Therefore, combining the above factors, the oil increment effect of sample (I) becomes worse. In additional, the results of field test verify the laboratory experiments. From the above research, we canconclude that the relationship between crude oil composition and ASP flooding is of great significance. As a result, this paper has carried out a lot of related research work and revealed the internal relationship between the two, which has important practical significance to improve the effect of increasing oil and reducing water in ASP flooding technology.
{"title":"Research on the Relationship Between Crude Oil Composition and Asp Flooding Effect","authors":"Zhe Sun, Xiaodong Kang, Shanshan Zhang","doi":"10.2118/204348-ms","DOIUrl":"https://doi.org/10.2118/204348-ms","url":null,"abstract":"\u0000 In recent years, ASP flooding has been widely applied and obtained the remarkable effect. During the ASP flooding process, the oil composition has a great effect on the interfacial tension, which plays a vital role in the oil displacement effect. However, through literature research, few have made a profound study on the effect of oil composition on the recover rate. As a result, it is very important to carry out relevant research.\u0000 For the oil sample (I) and sample (II) from two different regions in DQ, the crude oil composition analysis is first carried out. After the mixing of oil system and ASP system, the distribution ratio of agent is obtained. Furthermore, the oil composition does have an impact on the interfacial tension and recovery rate, and its influence law is explored. Finally, its application is introduced and analyzed.\u0000 Research results show that, compare with sample (II), the sample (I) has more heavy components. After the mixing of oil samples and ASP, more surfactant and alkali enters into the oil phase of sample (I). Therefore, based on the similar miscibility principle, the surfactant is more likely to leave the oil water interface and enter into the oil phase of sample (I), which has a negative effect on reducing the interfacial tension. Furthermore, the phenomenon of chromatographic separation aggravates the adsorption of surfactant on rock surface. Therefore, combining the above factors, the oil increment effect of sample (I) becomes worse. In additional, the results of field test verify the laboratory experiments.\u0000 From the above research, we canconclude that the relationship between crude oil composition and ASP flooding is of great significance. As a result, this paper has carried out a lot of related research work and revealed the internal relationship between the two, which has important practical significance to improve the effect of increasing oil and reducing water in ASP flooding technology.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87939816","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}
Despite attempts to inhibit or avoid the formation of fouling deposits (polymeric amorphous dithiazine or apDTZ for short) from the use of MEA triazine, this remains a major operational problem and limits the use of this most popular and ubiquitous hydrogen sulphide (H2S) scavenger. This paper (a) reviews and summarizes previous work, (b) provides fresh insights into the reaction product and mechanism of formation, (c) proposes an effective method of removal, and (d) proposes some mechanisms of apDTZ digestion. The mechanism of apDTZ formation is discussed and reasoning is provided from a variety of perspectives as to the mechanism of MEA-triazine reaction with H2S. These include basicity and nucleophilic substitution considerations, steric properties and theoretical calculations for electron density. Novel procedures to chemically react with and destroy this solid fouling are presented with an in-depth study and experimental verification of the underlying chemistry of this digestion process. A review of agents to chemically destroy apDTZ is undertaken and a very effective solution has been found in peroxyacetic acid, which is much more powerful and effective than previously suggested peroxides. The structure of amorphous polymeric dithiazine is emphasized and the reason why this fouling cannot be 1,3,5-trithiane is stressed. This work therefore overcomes a current industry misconception by providing insight on two major paradoxes in the reaction pathway; namely i) why the thiadiazine reaction product from tris hydroxyethyl triazine (MEA triazine) is never observed and ii) why does the dithiazine in all cases never progress to the trithiane (3rd sulphur molecule substitution)? The latter issue is probably the biggest misconception in the industry and literature regarding triazine and H2S reactions. Many reasons for this are put forward and the common misconception of "overspent" triazine is refuted. A very effective chemical reaction that results in soluble by-products, counteracting the problems produced by this intractable polymer is found and their composition is proposed and experimentally verified.
{"title":"Amorphous Polymeric Dithiazine apDTZ Solid Fouling: Critical Review, Analysis and Solution of an Ongoing Challenge in Triazine-Based Hydrogen Sulphide Mitigation","authors":"G. Taylor, J. Wylde, W. Samaniego, K. Sorbie","doi":"10.2118/204397-ms","DOIUrl":"https://doi.org/10.2118/204397-ms","url":null,"abstract":"\u0000 Despite attempts to inhibit or avoid the formation of fouling deposits (polymeric amorphous dithiazine or apDTZ for short) from the use of MEA triazine, this remains a major operational problem and limits the use of this most popular and ubiquitous hydrogen sulphide (H2S) scavenger. This paper (a) reviews and summarizes previous work, (b) provides fresh insights into the reaction product and mechanism of formation, (c) proposes an effective method of removal, and (d) proposes some mechanisms of apDTZ digestion. The mechanism of apDTZ formation is discussed and reasoning is provided from a variety of perspectives as to the mechanism of MEA-triazine reaction with H2S. These include basicity and nucleophilic substitution considerations, steric properties and theoretical calculations for electron density. Novel procedures to chemically react with and destroy this solid fouling are presented with an in-depth study and experimental verification of the underlying chemistry of this digestion process. A review of agents to chemically destroy apDTZ is undertaken and a very effective solution has been found in peroxyacetic acid, which is much more powerful and effective than previously suggested peroxides.\u0000 The structure of amorphous polymeric dithiazine is emphasized and the reason why this fouling cannot be 1,3,5-trithiane is stressed. This work therefore overcomes a current industry misconception by providing insight on two major paradoxes in the reaction pathway; namely i) why the thiadiazine reaction product from tris hydroxyethyl triazine (MEA triazine) is never observed and ii) why does the dithiazine in all cases never progress to the trithiane (3rd sulphur molecule substitution)? The latter issue is probably the biggest misconception in the industry and literature regarding triazine and H2S reactions. Many reasons for this are put forward and the common misconception of \"overspent\" triazine is refuted. A very effective chemical reaction that results in soluble by-products, counteracting the problems produced by this intractable polymer is found and their composition is proposed and experimentally verified.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89285348","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. Ferrar, Philip Maun, K. Wunch, Joseph D. Moore, Jana Rajan, J. Raymond, E. Solomon, M. Paschoalino
Preservative biocides are designed to control microbial growth and biogenic souring in the downhole environment. We report the prevention of biogenic souring by 4,4-dimethyloxazolidine (DMO, a preservative biocide) and glutaraldehyde as compared to that afforded by tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), in a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors that simulate hydraulically fractured shale reservoirs. The design of these new bioreactors, which recreate the downhole environment (temperatures, pressures, formation solids, and frac additives) in a controlled laboratory environment, enables the evaluation of biocides under field-relevant conditions. The bioreactors receiving either no biocide treatment or treatment with a high concentration of TTPC (50 ppm active ingredient) rapidly soured within the first two weeks of shut-in, and all surpassed the maximum detectable level of H2S (343 ppm) after the addition of live microbes to the reactors. Conversely, a higher loading of DMO (150 pppm active ingredient) maintained H2S concentrations below the minimum dectable level (5 ppm) for six weeks, and held H2S concentrations to 10.3 +/- 5.2 ppm after fifteen weeks of shut-in and two post shut-in microbial rechallenges. In a second study, a lower concentration of DMO (50 ppm active ingredient) maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations only registered above 10 ppm upon a second addition of live microbes after five weeks. In this same study (which was performed at moderate temperatures), a 50 ppm (active ingredient) treatment of glutaraldehyde also maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations registered 15.0 +/- 9.7 ppm H2S after four weeks. Similar time scales of protection are observed for each treatment condition through the enumeration of microbes present in each reactor. The differentiation in antimicrobial activity (and specifically, prevention of biogenic souring) afforded by DMO and glutaraldehyde suggests that such nonionic, preservative biocides are a superior choice for maintaining control over problematic microorganisms as compared to surface-active biocides like TTPC at the concentrations tested. The significant duration of efficacy provided by DMO and glutaraldehyde in this first-of-its-kind suite of simulated reservoirs demonstrates that comprehensive preservation and prevention of biogenic souring from completion through to production is feasible. Such comprehensive, prolonged protection is especially relevant for extended shut-ins or drilled but uncompleted wells (DUCS) such as those experienced during the COVID-19 pandemic. The environment simulated within the bioreactors demonstrates that the compatibility afforded by a preservative biocide offers downhole
{"title":"Extended Downhole Protection by Preservative Biocides as Demonstrated in High Pressure, High Temperature Bioreactors","authors":"J. Ferrar, Philip Maun, K. Wunch, Joseph D. Moore, Jana Rajan, J. Raymond, E. Solomon, M. Paschoalino","doi":"10.2118/204377-ms","DOIUrl":"https://doi.org/10.2118/204377-ms","url":null,"abstract":"\u0000 Preservative biocides are designed to control microbial growth and biogenic souring in the downhole environment. We report the prevention of biogenic souring by 4,4-dimethyloxazolidine (DMO, a preservative biocide) and glutaraldehyde as compared to that afforded by tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), in a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors that simulate hydraulically fractured shale reservoirs. The design of these new bioreactors, which recreate the downhole environment (temperatures, pressures, formation solids, and frac additives) in a controlled laboratory environment, enables the evaluation of biocides under field-relevant conditions.\u0000 The bioreactors receiving either no biocide treatment or treatment with a high concentration of TTPC (50 ppm active ingredient) rapidly soured within the first two weeks of shut-in, and all surpassed the maximum detectable level of H2S (343 ppm) after the addition of live microbes to the reactors. Conversely, a higher loading of DMO (150 pppm active ingredient) maintained H2S concentrations below the minimum dectable level (5 ppm) for six weeks, and held H2S concentrations to 10.3 +/- 5.2 ppm after fifteen weeks of shut-in and two post shut-in microbial rechallenges. In a second study, a lower concentration of DMO (50 ppm active ingredient) maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations only registered above 10 ppm upon a second addition of live microbes after five weeks. In this same study (which was performed at moderate temperatures), a 50 ppm (active ingredient) treatment of glutaraldehyde also maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations registered 15.0 +/- 9.7 ppm H2S after four weeks. Similar time scales of protection are observed for each treatment condition through the enumeration of microbes present in each reactor. The differentiation in antimicrobial activity (and specifically, prevention of biogenic souring) afforded by DMO and glutaraldehyde suggests that such nonionic, preservative biocides are a superior choice for maintaining control over problematic microorganisms as compared to surface-active biocides like TTPC at the concentrations tested.\u0000 The significant duration of efficacy provided by DMO and glutaraldehyde in this first-of-its-kind suite of simulated reservoirs demonstrates that comprehensive preservation and prevention of biogenic souring from completion through to production is feasible. Such comprehensive, prolonged protection is especially relevant for extended shut-ins or drilled but uncompleted wells (DUCS) such as those experienced during the COVID-19 pandemic. The environment simulated within the bioreactors demonstrates that the compatibility afforded by a preservative biocide offers downhole","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80337040","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}
Yingxian Ma, Liqiang Huang, Zhi Zhu, Yuliang Du, J. Lai, Jianchun Guo
Inspired by non-covalent enhancement mechanism, we introduced glycinamide-conjugated monomer (NAGA) with dual-amide in one side group to amplify the hydrogen bonding interactions. Via one-step free radical polymerization strategy, we prepared a type of supramolecular thickener based on binary polymer. With NMR, FT-IR and SEM results’ help, we determined that PNAGA-AM system had unique bis-amide structure of glycinamide-conjugated monomer. As a result, the synthesized polymer could generate a much denser structure based on the high-ordered multiple hydrogen bonding with lower molecular weight (Mn = 778,400 g/mol), increasing the strength and stability of the chains. PNAGA-AM system had good thickening and temperature-resistant properties. The thickener viscosity of PNAGA-AM(3.0wt%) had twice as much as that of corresponding PAM system. And the viscosity of the 1.5 wt% solution prepared by PNAGA-AM could maintain 74 mPa·s at 150 °C. Meanwhile, the supramolecular system showed excellent salt resistance and self-healing performance with the non-covalent/hydrogen bonding interactions and physical entanglements. The viscosity of the PNAGA-AM system did not drop but increase in high salinity (≤ 300,000 mg/L salinity), and the maximum viscosity could increase nearly 44 % compared with the initial situation. In addition, the self-healing efficiency was over 100 % at 120 °C. Overall, the fracturing fluid system based on PNAGA-AM system could maintain outstanding rheological properties under extreme conditions and showed brilliant recovery performance, to make up the disadvantages of currently used fracturing fluid. It is expected to mitigate potential fluid issues caused by low water quality, harsh downhole temperatures and high-speed shearing.
{"title":"A Supramolecular Thickener Based on Non-Covalent Enhancement Mechanism","authors":"Yingxian Ma, Liqiang Huang, Zhi Zhu, Yuliang Du, J. Lai, Jianchun Guo","doi":"10.2118/204299-ms","DOIUrl":"https://doi.org/10.2118/204299-ms","url":null,"abstract":"\u0000 Inspired by non-covalent enhancement mechanism, we introduced glycinamide-conjugated monomer (NAGA) with dual-amide in one side group to amplify the hydrogen bonding interactions. Via one-step free radical polymerization strategy, we prepared a type of supramolecular thickener based on binary polymer. With NMR, FT-IR and SEM results’ help, we determined that PNAGA-AM system had unique bis-amide structure of glycinamide-conjugated monomer. As a result, the synthesized polymer could generate a much denser structure based on the high-ordered multiple hydrogen bonding with lower molecular weight (Mn = 778,400 g/mol), increasing the strength and stability of the chains. PNAGA-AM system had good thickening and temperature-resistant properties. The thickener viscosity of PNAGA-AM(3.0wt%) had twice as much as that of corresponding PAM system. And the viscosity of the 1.5 wt% solution prepared by PNAGA-AM could maintain 74 mPa·s at 150 °C. Meanwhile, the supramolecular system showed excellent salt resistance and self-healing performance with the non-covalent/hydrogen bonding interactions and physical entanglements. The viscosity of the PNAGA-AM system did not drop but increase in high salinity (≤ 300,000 mg/L salinity), and the maximum viscosity could increase nearly 44 % compared with the initial situation. In addition, the self-healing efficiency was over 100 % at 120 °C. Overall, the fracturing fluid system based on PNAGA-AM system could maintain outstanding rheological properties under extreme conditions and showed brilliant recovery performance, to make up the disadvantages of currently used fracturing fluid. It is expected to mitigate potential fluid issues caused by low water quality, harsh downhole temperatures and high-speed shearing.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77103110","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}
Fabio Bordeaux Rego, S. Tavassoli, Esmail Eltahan, K. Sepehrnoori
Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.
{"title":"Geochemical Modeling of Petrophysical Alteration Effect on CO2 Injectivity in Carbonate Rocks","authors":"Fabio Bordeaux Rego, S. Tavassoli, Esmail Eltahan, K. Sepehrnoori","doi":"10.2118/204284-ms","DOIUrl":"https://doi.org/10.2118/204284-ms","url":null,"abstract":"\u0000 Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks.\u0000 In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity.\u0000 Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83353676","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. Beteta, O. Vazquez, M. A. Al Kalbani, Faith Eze
This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir versus a water flooded reservoir. A squeeze campaign was designed for the base water flood system, then injection was switched to polymer flooding at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during polymer flooding are studied using reservoir simulation. A two-dimensional 5-spot model was used in this study, considered a reasonable representation of a field scenario, where it was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation, the number of squeeze treatments was significantly reduced as compared to the water flood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, 0.5PV (reservoir pore volumes) of water injection, water cut approximately 70%, the number of squeeze treatments required was still lower than the water flood base case. However, it was also observed that in all cases, at later stages of field life the positive impacts of polymer flooding on squeeze lifetime begin to diminish, due in part to the high viscosity fluid now present in the production near-wellbore region. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, polymer flooding will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of polymer flooding in terms of scale management, aside from the enhanced oil recovery.
{"title":"Simulation of Scale Inhibitor Squeeze Treatments in a Polymer Flooded Reservoir","authors":"A. Beteta, O. Vazquez, M. A. Al Kalbani, Faith Eze","doi":"10.2118/204367-ms","DOIUrl":"https://doi.org/10.2118/204367-ms","url":null,"abstract":"\u0000 This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir versus a water flooded reservoir. A squeeze campaign was designed for the base water flood system, then injection was switched to polymer flooding at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system.\u0000 During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during polymer flooding are studied using reservoir simulation.\u0000 A two-dimensional 5-spot model was used in this study, considered a reasonable representation of a field scenario, where it was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation, the number of squeeze treatments was significantly reduced as compared to the water flood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, 0.5PV (reservoir pore volumes) of water injection, water cut approximately 70%, the number of squeeze treatments required was still lower than the water flood base case. However, it was also observed that in all cases, at later stages of field life the positive impacts of polymer flooding on squeeze lifetime begin to diminish, due in part to the high viscosity fluid now present in the production near-wellbore region.\u0000 This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, polymer flooding will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of polymer flooding in terms of scale management, aside from the enhanced oil recovery.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"608 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77638922","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 new cementing additive is chemically engineered to react with formation fluids that act antagonistically towards cement. Engineered polymer capsules house encapsulants to react with antagonistic gases downhole like CO2 to form a more benign and beneficial material. Embedded in cement, the polymer capsules with semi-permeable shells allow fluids to permeate and react with encapsulants to produce beneficial byproducts, such as calcite and water from CO2. Reactivity between the encapsulant and antagonist gas CO2 is demonstrated using thermal gravimetric analysis (TGA) and other tests from oilfield equipment. When cement fails, casing-in-casing events, or CCA, causes antagonistic gases like CO2 to migrate to the surface. Embedded in the cement for such moments such as cement failure, additives housed within polyaramide vesicles chemically and physically intersect CO2 from gas migration events. The shape of the polyaramide additive is unique and versatile. Furthermore, because the material is polymeric, it imparts beneficial mechanical properties like elasticity to cement. A vesicle in form, this polymer allows the manufacturing of new cement additives for applications such as increasing the integrity and sustainability of oil well cement. Data also shows production of calcite by the bulk of the material. This technology applies to CO2 fixation and self-healing cement using reactive polymer vesicles.
{"title":"Wellbore Integrity and CO2 Sequestration Using Polyaramide Vesicles","authors":"Elizabeth Q. Contreras","doi":"10.2118/204385-ms","DOIUrl":"https://doi.org/10.2118/204385-ms","url":null,"abstract":"\u0000 A new cementing additive is chemically engineered to react with formation fluids that act antagonistically towards cement. Engineered polymer capsules house encapsulants to react with antagonistic gases downhole like CO2 to form a more benign and beneficial material. Embedded in cement, the polymer capsules with semi-permeable shells allow fluids to permeate and react with encapsulants to produce beneficial byproducts, such as calcite and water from CO2. Reactivity between the encapsulant and antagonist gas CO2 is demonstrated using thermal gravimetric analysis (TGA) and other tests from oilfield equipment.\u0000 When cement fails, casing-in-casing events, or CCA, causes antagonistic gases like CO2 to migrate to the surface. Embedded in the cement for such moments such as cement failure, additives housed within polyaramide vesicles chemically and physically intersect CO2 from gas migration events. The shape of the polyaramide additive is unique and versatile. Furthermore, because the material is polymeric, it imparts beneficial mechanical properties like elasticity to cement. A vesicle in form, this polymer allows the manufacturing of new cement additives for applications such as increasing the integrity and sustainability of oil well cement. Data also shows production of calcite by the bulk of the material. This technology applies to CO2 fixation and self-healing cement using reactive polymer vesicles.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86799872","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}
V. Wagle, A. Al-Yami, Sara Alkhalaf, Khawlah Alanqari, Wajid Ali, Faisal Abdullah Al-Turki
A good primary cementing job governs in a great part the producing performance of a well. Successful zonal isolation, which is the main objective of any cementing job, primarily depends on the right cement design. The resin-based cement system, which is a relatively new technology within the oil industry has the potential to replace conventional cement in critical primary cementing applications. This paper describes the lab-testing and field deployment of the resin-based cement systems. The resin-based cement systems were deployed in those well sections where a potential high-pressure influx was expected. The resin-based cement system, which was placed as a tail slurry was designed to have better mechanical properties as compared to the conventional cement systems. The paper describes the process used to get the right resin-based cement slurry design and how its application was important to the success of the cementing jobs. The cement job was executed successfully and met all the zonal-isolation objectives. The resin-based cement's increased shear bond strength and better mechanical properties were deemed to be instrumental in providing a reliable barrier that would thwart any future issues arising due to sustained casing pressure (SCP). This paper describes the required lab-testing, lab-evaluation, and the successful field deployment of the resin-based cement systems.
{"title":"Novel Resin-Cement Blend to Improve Well Integrity","authors":"V. Wagle, A. Al-Yami, Sara Alkhalaf, Khawlah Alanqari, Wajid Ali, Faisal Abdullah Al-Turki","doi":"10.2118/204279-ms","DOIUrl":"https://doi.org/10.2118/204279-ms","url":null,"abstract":"\u0000 A good primary cementing job governs in a great part the producing performance of a well. Successful zonal isolation, which is the main objective of any cementing job, primarily depends on the right cement design. The resin-based cement system, which is a relatively new technology within the oil industry has the potential to replace conventional cement in critical primary cementing applications.\u0000 This paper describes the lab-testing and field deployment of the resin-based cement systems. The resin-based cement systems were deployed in those well sections where a potential high-pressure influx was expected. The resin-based cement system, which was placed as a tail slurry was designed to have better mechanical properties as compared to the conventional cement systems. The paper describes the process used to get the right resin-based cement slurry design and how its application was important to the success of the cementing jobs. The cement job was executed successfully and met all the zonal-isolation objectives. The resin-based cement's increased shear bond strength and better mechanical properties were deemed to be instrumental in providing a reliable barrier that would thwart any future issues arising due to sustained casing pressure (SCP). This paper describes the required lab-testing, lab-evaluation, and the successful field deployment of the resin-based cement systems.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84393914","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 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}
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