Gustavo Maya Toro, Julia Jineth Herrera Quintero, Rubén Hernán Castro García, Henderson Iván Quintero Pérez, Dalje Sunith Barbosa Trillos, L. Prada, Laura Maldonado Manrique, Eduar Pérez
With the design of experiments (DoE), this study analyses the influence of physical (capillary diameter and pressure drop) and chemical variables (salinity, polymer concentration, and molecular weight) on the mechanical degradation of partially hydrolyzed polyacrylamide-type polymer solutions (HPAM) used in enhanced oil recovery processes. Initially, with the help of a fractional factorial design (2k-p), the variables with the most significant influence on the polymer's mechanical degradation were found. The experimental results of the screening demonstrate that the factors that statistically influence the mechanical degradation are the molecular weight, the diameter of the capillary, and the pressure differential. Subsequently, a regression model was developed to estimate the degradation percentages of HPAM polymer solutions as a function of the significant factors influencing the mechanical degradation of polymer solutions. This model had a 97.85% fit for the predicted values under the experimental conditions. Likewise, through the optimization developed by the Box Behnken response surface methodology, it was determined that the pressure differential was the most influential factor. This variable was followed by the capillary diameter, where less than 50% degradation rates are obtained with low polymer molecular weight (6.5 MDa), pressure differentials less than 500 psi, and diameters of the capillary greater than 0.125 inches.
{"title":"Experimental evaluation of the mechanical degradation of HPAM polymeric solutions used in Enhanced Oil Recovery","authors":"Gustavo Maya Toro, Julia Jineth Herrera Quintero, Rubén Hernán Castro García, Henderson Iván Quintero Pérez, Dalje Sunith Barbosa Trillos, L. Prada, Laura Maldonado Manrique, Eduar Pérez","doi":"10.29047/01225383.275","DOIUrl":"https://doi.org/10.29047/01225383.275","url":null,"abstract":"With the design of experiments (DoE), this study analyses the influence of physical (capillary diameter and pressure drop) and chemical variables (salinity, polymer concentration, and molecular weight) on the mechanical degradation of partially hydrolyzed polyacrylamide-type polymer solutions (HPAM) used in enhanced oil recovery processes. Initially, with the help of a fractional factorial design (2k-p), the variables with the most significant influence on the polymer's mechanical degradation were found. The experimental results of the screening demonstrate that the factors that statistically influence the mechanical degradation are the molecular weight, the diameter of the capillary, and the pressure differential. Subsequently, a regression model was developed to estimate the degradation percentages of HPAM polymer solutions as a function of the significant factors influencing the mechanical degradation of polymer solutions. This model had a 97.85% fit for the predicted values under the experimental conditions. Likewise, through the optimization developed by the Box Behnken response surface methodology, it was determined that the pressure differential was the most influential factor. This variable was followed by the capillary diameter, where less than 50% degradation rates are obtained with low polymer molecular weight (6.5 MDa), pressure differentials less than 500 psi, and diameters of the capillary greater than 0.125 inches.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82532065","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}
Gonzalo Gallo, Raul Puliti, R. Torres, Eleonora Erdmann
Given the growing interest in the capture and utilization of CO2 in recent years, several technologies have emerged that seek to generate CO2 in-situ at a low cost. There are promising developments, which allow capturing CO2 with sufficient purity to be used for EOR. Oxycombustion has high potential in the region as this technology benefits from gas production with a high CO2 content, which significantly reduces the cost of capture. Additionally, carbon dioxide separation techniques such as air capture, fuel cells, amines, and membranes are considered. Argentina has several fields, which produce gas with high CO2 content benefiting Oxycombustion economics. The paradigm change not only occurs in technology but also in the implementation schemes. The vast majority of the development of CO2 EOR are carried out in the USA with very low CO2 costs and high availability. When considering the costs of CO2 per ton (metric ton) that could be obtained in Argentina, and financial variables such as high discount rates, it is clear that the injection model has to be optimized for these conditions. In order to optimize profitability, it is crucial to improve the payout time and the usage of CO2. In one hand, smaller slugs lead to better CO2 utilization rates (oil produced/CO2 injected) while larger slugs lead to faster oil production response. We observed that due to the high discount rates in the area, faster production response has a higher economic impact that sweep efficiency or breakthrough times. It seems to be better to sacrifice overall recovery factor in order to extract oil as soon as possible. Optimal injection schemes where found for different scenarios. Additionally, starting the project early is a key parameter for both technical and economic success. Another key technical difference is that the available CO2 volume for injection is constant due to the nature of these capture techniques. Unlike purchasing CO2 from a pipeline, where gas can be purchased as needed, Oxycombustion (or other capture methods) produces a continuous stream limiting injection flexibility. All produced CO2 must be injected as it is being produced and, until production gas reaches a CO2 content high enough to assure MMP, CO2 injection stream cannot exceed the maximum CO2 capture capacity. CO2 EOR has significant advantages over Chemical EOR due to its significant recovery factors and early response. Additionally, this technology applies to reservoirs of low permeability and / or high temperature where the polymer can have problems of injectivity or degradation.
{"title":"CO2 EOR with in-situ CO2 capture, a Neuquina basin oxycombustion case study","authors":"Gonzalo Gallo, Raul Puliti, R. Torres, Eleonora Erdmann","doi":"10.29047/01225383.250","DOIUrl":"https://doi.org/10.29047/01225383.250","url":null,"abstract":"Given the growing interest in the capture and utilization of CO2 in recent years, several technologies have emerged that seek to generate CO2 in-situ at a low cost. There are promising developments, which allow capturing CO2 with sufficient purity to be used for EOR. Oxycombustion has high potential in the region as this technology benefits from gas production with a high CO2 content, which significantly reduces the cost of capture. Additionally, carbon dioxide separation techniques such as air capture, fuel cells, amines, and membranes are considered. Argentina has several fields, which produce gas with high CO2 content benefiting Oxycombustion economics. \u0000The paradigm change not only occurs in technology but also in the implementation schemes. The vast majority of the development of CO2 EOR are carried out in the USA with very low CO2 costs and high availability. When considering the costs of CO2 per ton (metric ton) that could be obtained in Argentina, and financial variables such as high discount rates, it is clear that the injection model has to be optimized for these conditions. In order to optimize profitability, it is crucial to improve the payout time and the usage of CO2. In one hand, smaller slugs lead to better CO2 utilization rates (oil produced/CO2 injected) while larger slugs lead to faster oil production response. We observed that due to the high discount rates in the area, faster production response has a higher economic impact that sweep efficiency or breakthrough times. It seems to be better to sacrifice overall recovery factor in order to extract oil as soon as possible. Optimal injection schemes where found for different scenarios. Additionally, starting the project early is a key parameter for both technical and economic success. \u0000 \u0000Another key technical difference is that the available CO2 volume for injection is constant due to the nature of these capture techniques. Unlike purchasing CO2 from a pipeline, where gas can be purchased as needed, Oxycombustion (or other capture methods) produces a continuous stream limiting injection flexibility. All produced CO2 must be injected as it is being produced and, until production gas reaches a CO2 content high enough to assure MMP, CO2 injection stream cannot exceed the maximum CO2 capture capacity. \u0000CO2 EOR has significant advantages over Chemical EOR due to its significant recovery factors and early response. Additionally, this technology applies to reservoirs of low permeability and / or high temperature where the polymer can have problems of injectivity or degradation. ","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"115 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80608694","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}
Henderson Iván Quintero Pérez, Miguel José Rondon Anton, Jaime Alberto Jimenez, J. Bermudez, Julian Alfredo Gonzalez, Jenny Liset Rodrigues, Carlos Espinosa Leon
Chemical formulations, including surfactants, polymers, alkalis, or their combinations, are widely used in different oil recovery processes to improve water injection performance. However, based on challenging profit margins in most mature waterfloods in Colombia and overseas, it is necessary to explore alternatives that could offer better performance and greater operational flexibility than the conventional technologies used for enhanced oil recovery (EOR) processes. Polymeric surfactants are compounds widely used in the manufacture of domestic and industrial cleaning, pharmaceutical, cosmetic, and food products. These compounds represent an interesting alternative as they can simultaneously increase the viscosity in water solution and reduce the interfacial tension (IFT) in the water/oil system, which would increase the efficiency of EOR processes. This article shows a methodological evaluation through laboratory studies, numerical reservoir simulation, and conceptual engineering design to apply polymeric surfactants (Block Copolymer Polymeric Surfactants or BCPS) as additives to improve efficiency in water injection processes. Block copolymer type products of ethylene oxide (EO) - propylene oxide (PO) - ethylene oxide (EO) in aqueous solution were studied to determine their rheological and surfactant behavior under the operating conditions of a Colombian field. In the conditions studied, these products allow to reduce the interfacial tension up to 2x10-1 mN/m values and also cause a shear-thinning rheological behavior following the power law at very low shear rates (0.1 s-1– 1 s-1), which corresponds to an increase up to four orders of magnitude in the capillary number (Nc). The IFT and the viscosity reached are maintained in wide ranges of salinity, BCPS concentration, and shear rates, making it a robust performance formulation. In a model porous medium, BCPS tested have moderate adsorption, less than conventional surfactants but higher than HPAM polymers, in any way allowing a favorable wettability condition. Additionally, it was observed that they offer a resistance factor up to 16 times, causing greater displacement efficiency than water injection, allowing better sweeping in low permeability areas without injectivity restrictions. Numerical simulation shows that it is possible to reach incremental production up to 238,5 TBO by injecting a continuous slug of 0.15 pore volumes of BCPS and HPAM, each with 2,000 ppm concentration and a flow rate of 2,500 BPD. As BCPS are simple handling and dilution products, these could be injected directly in water injection flow using a high precision dosing pump with high pressure and flow rate operational variables.
{"title":"Polymeric surfactants as alternative to improve waterflooding oil recovery efficiency","authors":"Henderson Iván Quintero Pérez, Miguel José Rondon Anton, Jaime Alberto Jimenez, J. Bermudez, Julian Alfredo Gonzalez, Jenny Liset Rodrigues, Carlos Espinosa Leon","doi":"10.29047/01225383.272","DOIUrl":"https://doi.org/10.29047/01225383.272","url":null,"abstract":"Chemical formulations, including surfactants, polymers, alkalis, or their combinations, are widely used in different oil recovery processes to improve water injection performance. However, based on challenging profit margins in most mature waterfloods in Colombia and overseas, it is necessary to explore alternatives that could offer better performance and greater operational flexibility than the conventional technologies used for enhanced oil recovery (EOR) processes. \u0000Polymeric surfactants are compounds widely used in the manufacture of domestic and industrial cleaning, pharmaceutical, cosmetic, and food products. These compounds represent an interesting alternative as they can simultaneously increase the viscosity in water solution and reduce the interfacial tension (IFT) in the water/oil system, which would increase the efficiency of EOR processes. \u0000This article shows a methodological evaluation through laboratory studies, numerical reservoir simulation, and conceptual engineering design to apply polymeric surfactants (Block Copolymer Polymeric Surfactants or BCPS) as additives to improve efficiency in water injection processes. Block copolymer type products of ethylene oxide (EO) - propylene oxide (PO) - ethylene oxide (EO) in aqueous solution were studied to determine their rheological and surfactant behavior under the operating conditions of a Colombian field. \u0000In the conditions studied, these products allow to reduce the interfacial tension up to 2x10-1 mN/m values and also cause a shear-thinning rheological behavior following the power law at very low shear rates (0.1 s-1– 1 s-1), which corresponds to an increase up to four orders of magnitude in the capillary number (Nc). The IFT and the viscosity reached are maintained in wide ranges of salinity, BCPS concentration, and shear rates, making it a robust performance formulation. \u0000 In a model porous medium, BCPS tested have moderate adsorption, less than conventional surfactants but higher than HPAM polymers, in any way allowing a favorable wettability condition. Additionally, it was observed that they offer a resistance factor up to 16 times, causing greater displacement efficiency than water injection, allowing better sweeping in low permeability areas without injectivity restrictions. \u0000Numerical simulation shows that it is possible to reach incremental production up to 238,5 TBO by injecting a continuous slug of 0.15 pore volumes of BCPS and HPAM, each with 2,000 ppm concentration and a flow rate of 2,500 BPD. As BCPS are simple handling and dilution products, these could be injected directly in water injection flow using a high precision dosing pump with high pressure and flow rate operational variables.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84171337","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}
Rubén Hernán Castro García, Sebastián Llanos Gallo, Jenny Liseth Rodriguez Ardila, Henderson Iván Quintero Pérez, E. J. Manrique Ventura, José Francisco Zapata Arango
Polymer flooding represents the most common chemical enhanced oil recovery (CEOR) method used at commercial scale. In this process, the polymeric solutions (generally hydrolyzed polyacrylamide - HPAM) are injected to improve the oil/water mobility ratio (M). However, due to mechanical, chemical, bio, and thermal degradation, polymer viscosity losses can occur, causing a negative impact on oil sweep efficiency. In this case, biopolymers seem to be promising candidates in EOR applications with special structural characteristics, which result in excellent stability in harsh environments with high temperatures, ionic forces, and shear stresses. This paper presents the laboratory evaluation of Scleroglucan (SG) and a commercial sulfonated polyacrylamide (ATBS) in synthetic brine, representative of a Colombian heavy-oil field. The effects of ionic strength, pH, temperature, and shear degradation effects on polymer viscosity were also evaluated. For SG, the results reflect its tolerance to high salinities (0-5%wt), ionic strengths (Na+, K+, Ca2+, and Mg2+), shear rates (0-300,000 s-1), temperatures (30, 50, 80 and 100 °C), and pH variations (3-10). The biopolymer was capable of preserving its viscous properties and stability after of the effect of these variables. Finally, the target viscosity (set as 17 cp) was achieved with a lower concentration (2.7 times) than the ATBS polymer tested.
{"title":"Heavy Oil and High-Temperature Polymer EOR Applications","authors":"Rubén Hernán Castro García, Sebastián Llanos Gallo, Jenny Liseth Rodriguez Ardila, Henderson Iván Quintero Pérez, E. J. Manrique Ventura, José Francisco Zapata Arango","doi":"10.29047/01225383.258","DOIUrl":"https://doi.org/10.29047/01225383.258","url":null,"abstract":"Polymer flooding represents the most common chemical enhanced oil recovery (CEOR) method used at commercial scale. In this process, the polymeric solutions (generally hydrolyzed polyacrylamide - HPAM) are injected to improve the oil/water mobility ratio (M). However, due to mechanical, chemical, bio, and thermal degradation, polymer viscosity losses can occur, causing a negative impact on oil sweep efficiency. In this case, biopolymers seem to be promising candidates in EOR applications with special structural characteristics, which result in excellent stability in harsh environments with high temperatures, ionic forces, and shear stresses. This paper presents the laboratory evaluation of Scleroglucan (SG) and a commercial sulfonated polyacrylamide (ATBS) in synthetic brine, representative of a Colombian heavy-oil field. The effects of ionic strength, pH, temperature, and shear degradation effects on polymer viscosity were also evaluated. For SG, the results reflect its tolerance to high salinities (0-5%wt), ionic strengths (Na+, K+, Ca2+, and Mg2+), shear rates (0-300,000 s-1), temperatures (30, 50, 80 and 100 °C), and pH variations (3-10). The biopolymer was capable of preserving its viscous properties and stability after of the effect of these variables. Finally, the target viscosity (set as 17 cp) was achieved with a lower concentration (2.7 times) than the ATBS polymer tested.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"104 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80449016","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}
I. D. Piñerez Torrijos, A. Mamonov, S. Strand, T. Puntervold
An appropriated wettability characterization is crucial for the successful implementation of waterflooding operations. Understanding how crude oil adsorption takes place on different mineral surfaces and how these processes impact reservoir wettability are essential aspects that can help unlock and produce large underground oil reserves. Polar organic components (POC) present in crude oil are surface-active molecules with high affinity towards mineral surfaces. POCs are quantified by the acid and base numbers (AN and BN) with units of mgKOH/g. The POC adsorption behavior is highly influenced by the type of minerals and brines present in the reservoir system. This study aims to shed light onto the most important features of oil adsorption on carbonates and sandstones mineral surfaces; particular attention is given to the role of acidic components. Therefore, outcrop sandstone and carbonate materials were used. The sandstone material contains various silicates, including quartz, Illite clay, and feldspars. The carbonate outcrop material came from the Stevns Klint quarry in Denmark and is considered a very pure calcium carbonate with minimum silicate impurities. Dynamic adsorption tests were performed at 50°C by injecting low asphaltene crude oils into core plugs, and AN and BN values of the effluent oil samples were measured and compared with the influent oil values. Furthermore, spontaneous imbibition (SI) tests were performed to assess the wettability impact of crude oil injection in oil flooded cores. The results showed that after crude oil injection, the cores became mix-wet. Confirmation of a reduction in capillary forces and a shift towards a less water-wet state was reported for both mineralogies, i.e., sandstones and carbonates. The acidic polar components had a substantial impact on carbonates wettability, while on sandstones, the experiments suggested that acidic polar components had a lower impact on wettability than that observed in the basic polar components.
{"title":"The role of polar organic components in dynamic crude oil adsorption on sandstones and carbonates","authors":"I. D. Piñerez Torrijos, A. Mamonov, S. Strand, T. Puntervold","doi":"10.29047/01225383.251","DOIUrl":"https://doi.org/10.29047/01225383.251","url":null,"abstract":"An appropriated wettability characterization is crucial for the successful implementation of waterflooding operations. Understanding how crude oil adsorption takes place on different mineral surfaces and how these processes impact reservoir wettability are essential aspects that can help unlock and produce large underground oil reserves. \u0000Polar organic components (POC) present in crude oil are surface-active molecules with high affinity towards mineral surfaces. POCs are quantified by the acid and base numbers (AN and BN) with units of mgKOH/g. The POC adsorption behavior is highly influenced by the type of minerals and brines present in the reservoir system. \u0000This study aims to shed light onto the most important features of oil adsorption on carbonates and sandstones mineral surfaces; particular attention is given to the role of acidic components. Therefore, outcrop sandstone and carbonate materials were used. The sandstone material contains various silicates, including quartz, Illite clay, and feldspars. The carbonate outcrop material came from the Stevns Klint quarry in Denmark and is considered a very pure calcium carbonate with minimum silicate impurities. \u0000Dynamic adsorption tests were performed at 50°C by injecting low asphaltene crude oils into core plugs, and AN and BN values of the effluent oil samples were measured and compared with the influent oil values. Furthermore, spontaneous imbibition (SI) tests were performed to assess the wettability impact of crude oil injection in oil flooded cores. \u0000The results showed that after crude oil injection, the cores became mix-wet. Confirmation of a reduction in capillary forces and a shift towards a less water-wet state was reported for both mineralogies, i.e., sandstones and carbonates. The acidic polar components had a substantial impact on carbonates wettability, while on sandstones, the experiments suggested that acidic polar components had a lower impact on wettability than that observed in the basic polar components.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75648669","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}
Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks. The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions. Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies. Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.
{"title":"Effect of ionic strength in low salinity water injection processes","authors":"Gustavo Maya Toro, Luisana Cardona Rojas, Mayra Fernanda Rueda Pelayo, Farid B. Cortes Correa","doi":"10.29047/01225383.269","DOIUrl":"https://doi.org/10.29047/01225383.269","url":null,"abstract":"Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks. \u0000The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions. \u0000Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies. \u0000Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85591086","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}
Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data. The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.
{"title":"Downhole electric heating of heavy-oil wells","authors":"J. Karanikas, G. Pastor, S. Penny","doi":"10.29047/01225383.273","DOIUrl":"https://doi.org/10.29047/01225383.273","url":null,"abstract":"Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. \u0000The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. \u0000A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data. The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. \u0000Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88614804","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}
Romel Perez, Hugo Garcia Duarte, L. Osma, Carolina Barbosa Goldstein, Luis Eduardo Garcia Rodríguez, Jesus Alberto Botett Cervantes, Hector Arnoldo Rodriguez Prada, E. Manrique
The development of heavy oil reservoirs under steam injection methods is facing multiple challenges due to the volatility of oil markets, energy efficiency, and new and stricter environmental regulations. This study aims to summarize the advances of a Research and Development (R&D) program established by Ecopetrol in 2018 to identify potential opportunities to improve the recovery performance of steam injection projects in heavyoil reservoirs in the Middle Valley Magdalena Basin (VMM) of Colombia.This paper summarizes an approach used to evaluate downhole heating and hybrid steam injection technologies assisted by basic benefit-cost ratios and energy and environmental indexes.Specifically, the methodology is described for the identification of optimum development plan scenarios for heavy oil wells. This study also summarizes recent advances in laboratory studies for the evaluation of hybrid steam flooding technologies (steam plus flue gas and solvents) and provides updates on the hybrid cyclicsteam-foam pilot carried out in two VMM wells.The proposed approach represents a fast screening method that has proven to be valuable in supporting management decision-making to allocate resources for laboratory and engineering studies to evaluate thermal enhanced oil recovery (tEOR) technologies in Colombia. The proposed methodology has also contributed to reducing the implementation cycle of tEOR technologies following the reservoir analog description ofreserve analysis. The latter was validated with the successful pilot results of the hybrid steam injection with foams implemented in July 2019.
{"title":"Downhole heating and hybrid cyclic steam methods: evaluating technologies from the laboratory to the field","authors":"Romel Perez, Hugo Garcia Duarte, L. Osma, Carolina Barbosa Goldstein, Luis Eduardo Garcia Rodríguez, Jesus Alberto Botett Cervantes, Hector Arnoldo Rodriguez Prada, E. Manrique","doi":"10.29047/01225383.257","DOIUrl":"https://doi.org/10.29047/01225383.257","url":null,"abstract":"The development of heavy oil reservoirs under steam injection methods is facing multiple challenges due to the volatility of oil markets, energy efficiency, and new and stricter environmental regulations. This study aims to summarize the advances of a Research and Development (R&D) program established by Ecopetrol in 2018 to identify potential opportunities to improve the recovery performance of steam injection projects in heavyoil reservoirs in the Middle Valley Magdalena Basin (VMM) of Colombia.This paper summarizes an approach used to evaluate downhole heating and hybrid steam injection technologies assisted by basic benefit-cost ratios and energy and environmental indexes.Specifically, the methodology is described for the identification of optimum development plan scenarios for heavy oil wells. This study also summarizes recent advances in laboratory studies for the evaluation of hybrid steam flooding technologies (steam plus flue gas and solvents) and provides updates on the hybrid cyclicsteam-foam pilot carried out in two VMM wells.The proposed approach represents a fast screening method that has proven to be valuable in supporting management decision-making to allocate resources for laboratory and engineering studies to evaluate thermal enhanced oil recovery (tEOR) technologies in Colombia. The proposed methodology has also contributed to reducing the implementation cycle of tEOR technologies following the reservoir analog description ofreserve analysis. The latter was validated with the successful pilot results of the hybrid steam injection with foams implemented in July 2019.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87649904","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}
Henderson Iván Quintero Pérez, Maria Carolina Ruiz Cañas, Rubén Hernán Castro García, Arnold R. Romero Bohórquez
Partially Hydrolyzed Polyacrylamide (HPAM) is the polymer most used in chemical enhanced oil recovery (cEOR) processes and it has been implemented in several field projects worldwide. Polymer injection has shown to be an effective EOR process. However, it has not been implemented massively due to HPAM polymer's limitations, mostly related to thermal and chemical degradation caused by exposure at high temperatures and salinities (HTHS). As an alternative, a new generation of chemically stable monomers to improve the properties of HPAM has been assessed at laboratory and field conditions. However, the use of enhanced polymers is limited due to its larger molecular size, large-scale production, and higher costs. One of the alternatives proposed in the last decade to improve polymer properties is the use of nanoparticles, which due to their ultra-small size, large surface area, and highly reactive capacity, can contribute to reduce or avoid the degrading processes of HPAM polymers. Nanoparticles (NPs) can be integrated with the polymer in several ways, it being worth to highlight mixing with the polymer in aqueous solution or inclusion by grafting or chemical functionalization on the nanoparticle surface. This review focuses on hybrid nanomaterials based on SiO2 NPs and synthetic polymers with great EOR potential. The synthesis process, characterization, and the main properties for application in EOR processes, were reviewed and analyzed. Nanohybrids based on polymers and silica nanoparticles show promising results in improving viscosity and thermal stability compared to the HPAM polymer precursor. Furthermore, based on recent findings, there are great opportunities to implement polymer nanofluids in cEOR projects. This approach could be of value to optimize the technical-economic feasibility of projects by reducing the polymer concentration of using reasonable amounts of nanoparticles. However, more significant efforts are required to understand the impact of nanoparticle concentrations and injection rates to support the upscaling of this cEOR technology.
{"title":"Use of nanoparticles to improve thermochemical resistance of synthetic polymer to enhanced oil recovery applications: a review","authors":"Henderson Iván Quintero Pérez, Maria Carolina Ruiz Cañas, Rubén Hernán Castro García, Arnold R. Romero Bohórquez","doi":"10.29047/01225383.259","DOIUrl":"https://doi.org/10.29047/01225383.259","url":null,"abstract":"Partially Hydrolyzed Polyacrylamide (HPAM) is the polymer most used in chemical enhanced oil recovery (cEOR) processes and it has been implemented in several field projects worldwide. Polymer injection has shown to be an effective EOR process. However, it has not been implemented massively due to HPAM polymer's limitations, mostly related to thermal and chemical degradation caused by exposure at high temperatures and salinities (HTHS). As an alternative, a new generation of chemically stable monomers to improve the properties of HPAM has been assessed at laboratory and field conditions. However, the use of enhanced polymers is limited due to its larger molecular size, large-scale production, and higher costs. \u0000One of the alternatives proposed in the last decade to improve polymer properties is the use of nanoparticles, which due to their ultra-small size, large surface area, and highly reactive capacity, can contribute to reduce or avoid the degrading processes of HPAM polymers. Nanoparticles (NPs) can be integrated with the polymer in several ways, it being worth to highlight mixing with the polymer in aqueous solution or inclusion by grafting or chemical functionalization on the nanoparticle surface. This review focuses on hybrid nanomaterials based on SiO2 NPs and synthetic polymers with great EOR potential. The synthesis process, characterization, and the main properties for application in EOR processes, were reviewed and analyzed. \u0000Nanohybrids based on polymers and silica nanoparticles show promising results in improving viscosity and thermal stability compared to the HPAM polymer precursor. Furthermore, based on recent findings, there are great opportunities to implement polymer nanofluids in cEOR projects. This approach could be of value to optimize the technical-economic feasibility of projects by reducing the polymer concentration of using reasonable amounts of nanoparticles. However, more significant efforts are required to understand the impact of nanoparticle concentrations and injection rates to support the upscaling of this cEOR technology.","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85262540","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. Caballero, Julian Naranjo Vesga, P. Gutiérrez, G. Forero, Andrés Roberto Mora Bohorquez, Wilson Miller Franco Castro, Jaime Ricardo Gelvez Llanez, C. Villamizar
This work presents the facies analysis and depositional environment for the Eocene rocks in the southern Llanos Basin (SLLB) and southern Llanos Foothills. Cores and outcrop samples were analyzed by palynology and detrital zircon U-Pbgeochronology. In this paper, we present ages for the facies and two important paleosol markers. The lower member of the Mirador Formation consists of amalgamated sandstones and conglomerates accumulated in a braidad channel belt. The lower Mirador is 33 m thick and early Eocene in the Foothills, whereas in the SLLB, it ist is 22 m thick and middle Eocene in age; it pinches out approximately 33 km to the east. The fluvial facies rests over an unconformity marked by a mature and intensively-weathered paleosol developed over Paleocene, Cretaceous and older rocks to the east. This mature paleosol was dated by U-Pb detrital zircon geochronology as middle to late Paleocene. At the top of the lower Mirador, we describe an interval of sandstones with root casts capped by a thin layer of coal or coaly mudstone. This facies succession evolved as A compound paleosol is a polygenetic soil that marks a change from well-drained conditions under a subaerial vegetation cover to poor-drained conditions of marsh and swamps, which halt vegetation growth, which is incorporated as coal or coaly mudstone, see the section of Facies Successions. At the top of the lower Mirador facies and recorded the cessation of the fluvial system and its stabilization by vegetation. The coal layer marked the posterior rise on the water table and flooding. Detrital zircon U-Pb geochronology dated this compound paleosol as middle Eocene. Above the fluvial facies of the lower Mirador, shallow marine facies deposited during the middle and late Eocene in the Foothills and western SLLB. The marine facies consist in shelf mudstone and shoreface sandstone in a coarsening upward trend. These facies correspond to the C8 member of the Carbonera Formation. The correlative middle Eocene facies to the east of the SLLB are carbonaceous mudstones and coals that were deposited in swamp-marsh and lagoon environments in backshore to coastal-plain environments during the middle Eocene. The fluvial and coastal plain, as well as the marine facies, fossilized an erosional relief less than 50 m high, corresponding to a paleo-landscape. The paleo-landscape was carved at the end of the Paleocene and is capped by the intensely-weathered paleosol indicating subaerial exposition. The paleo-landscape was modeled over Paleocene, Cretaceous, Paleozoic, and basement rocks toward the east and south of the basin. This paleo-landscape lasted until the end of the middle Eocene in the studied area. The Fluvial reservoirs are not continuous but distributed along channel belts composed of channels and braided bars in an NW direction. The marine shoreface reservoirs are distributed as swaths of sandstones in a perpendicular direction to the fluvial belts. These reservoirs have excellent sea
{"title":"Eocene facies successions and environments in the Southern Llanos basin, Colombia","authors":"V. Caballero, Julian Naranjo Vesga, P. Gutiérrez, G. Forero, Andrés Roberto Mora Bohorquez, Wilson Miller Franco Castro, Jaime Ricardo Gelvez Llanez, C. Villamizar","doi":"10.29047/01225383.141","DOIUrl":"https://doi.org/10.29047/01225383.141","url":null,"abstract":"This work presents the facies analysis and depositional environment for the Eocene rocks in the southern Llanos Basin (SLLB) and southern Llanos Foothills. Cores and outcrop samples were analyzed by palynology and detrital zircon U-Pbgeochronology. In this paper, we present ages for the facies and two important paleosol markers. \u0000The lower member of the Mirador Formation consists of amalgamated sandstones and conglomerates accumulated in a braidad channel belt. The lower Mirador is 33 m thick and early Eocene in the Foothills, whereas in the SLLB, it ist is 22 m thick and middle Eocene in age; it pinches out approximately 33 km to the east. The fluvial facies rests over an unconformity marked by a mature and intensively-weathered paleosol developed over Paleocene, Cretaceous and older rocks to the east. This mature paleosol was dated by U-Pb detrital zircon geochronology as middle to late Paleocene. At the top of the lower Mirador, we describe an interval of sandstones with root casts capped by a thin layer of coal or coaly mudstone. This facies succession evolved as A compound paleosol is a polygenetic soil that marks a change from well-drained conditions under a subaerial vegetation cover to poor-drained conditions of marsh and swamps, which halt vegetation growth, which is incorporated as coal or coaly mudstone, see the section of Facies Successions. At the top of the lower Mirador facies and recorded the cessation of the fluvial system and its stabilization by vegetation. The coal layer marked the posterior rise on the water table and flooding. Detrital zircon U-Pb geochronology dated this compound paleosol as middle Eocene. \u0000Above the fluvial facies of the lower Mirador, shallow marine facies deposited during the middle and late Eocene in the Foothills and western SLLB. The marine facies consist in shelf mudstone and shoreface sandstone in a coarsening upward trend. These facies correspond to the C8 member of the Carbonera Formation. The correlative middle Eocene facies to the east of the SLLB are carbonaceous mudstones and coals that were deposited in swamp-marsh and lagoon environments in backshore to coastal-plain environments during the middle Eocene. \u0000The fluvial and coastal plain, as well as the marine facies, fossilized an erosional relief less than 50 m high, corresponding to a paleo-landscape. The paleo-landscape was carved at the end of the Paleocene and is capped by the intensely-weathered paleosol indicating subaerial exposition. The paleo-landscape was modeled over Paleocene, Cretaceous, Paleozoic, and basement rocks toward the east and south of the basin. This paleo-landscape lasted until the end of the middle Eocene in the studied area. \u0000The Fluvial reservoirs are not continuous but distributed along channel belts composed of channels and braided bars in an NW direction. The marine shoreface reservoirs are distributed as swaths of sandstones in a perpendicular direction to the fluvial belts. These reservoirs have excellent sea","PeriodicalId":10745,"journal":{"name":"CT&F - Ciencia, Tecnología y Futuro","volume":"140 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-06-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82482733","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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