Q. Hou, Xiaobo Zheng, D. Guo, Youyi Zhu, Hui Yang, Xingguang Xu, Yuanyuan Wang, Chen Gang, Guangxin Hu, Jinben Wang
Stimuli-responsive emulsions have attracted much attention in diverse fields. However, research on the rapid and effective demulsification based on pH-responsive emulsions has barely been reported, although they are viewed as promising canditates for oil-water separation processes after oil recovery. In the present work, we have successfully synthesized a series of pH-responsive emulsions on the basis of a novel polymer containing amphiphilic and protonated moieties. The properties of these pH-responsive emulsions including stability, morphology microscopy, Zeta potential, and interfacial tension have been extensively investigated. We observed that the prepared oil-in-water emulsion could stay stable for more than 24 h within the pH range of 8-10, while it lost 80-90% of the water in 10-20 min if the pH was adjusted to 2-4. The variation in emulsion stability can be attributed to the protonation of poly [2-(N, N-diethylamino) ethyl methacrylate] (PDEA) residues at low pH values. Accordingly the polymers intend to become more hydrophilic and depart from the oil-water interface, leading to an increased interfacial tension. Furthermore, it was found that the applied polymers aggregated at the oil-water interface and that the morphology of aggregations was strongly affected by the pH values. These proposed polymers enabled the formation of emulsion with a controllable response to the pH stimuli. This work is expected to shed light on the development of stimuli-responsive emulsions and may have significant implications in the fields of oil recovery, waste water treatment, and so forth. For example, due to the high w/o interface activity of surfactants such as heavy alkyl benzene sulfonate (HABS) and petroleum sulfonate, severe emulsion has also been found with the alkali-surfactant-polymer (ASP) produced fluid. Currently, rapid breaking of these emulsion fluid is still a big challenge.
{"title":"PDEA-Based Amphiphilic Polymer Enables pH-Responsive Emulsions for a Rapid Demulsification","authors":"Q. Hou, Xiaobo Zheng, D. Guo, Youyi Zhu, Hui Yang, Xingguang Xu, Yuanyuan Wang, Chen Gang, Guangxin Hu, Jinben Wang","doi":"10.2118/193640-MS","DOIUrl":"https://doi.org/10.2118/193640-MS","url":null,"abstract":"\u0000 Stimuli-responsive emulsions have attracted much attention in diverse fields. However, research on the rapid and effective demulsification based on pH-responsive emulsions has barely been reported, although they are viewed as promising canditates for oil-water separation processes after oil recovery. In the present work, we have successfully synthesized a series of pH-responsive emulsions on the basis of a novel polymer containing amphiphilic and protonated moieties. The properties of these pH-responsive emulsions including stability, morphology microscopy, Zeta potential, and interfacial tension have been extensively investigated. We observed that the prepared oil-in-water emulsion could stay stable for more than 24 h within the pH range of 8-10, while it lost 80-90% of the water in 10-20 min if the pH was adjusted to 2-4. The variation in emulsion stability can be attributed to the protonation of poly [2-(N, N-diethylamino) ethyl methacrylate] (PDEA) residues at low pH values. Accordingly the polymers intend to become more hydrophilic and depart from the oil-water interface, leading to an increased interfacial tension. Furthermore, it was found that the applied polymers aggregated at the oil-water interface and that the morphology of aggregations was strongly affected by the pH values. These proposed polymers enabled the formation of emulsion with a controllable response to the pH stimuli. This work is expected to shed light on the development of stimuli-responsive emulsions and may have significant implications in the fields of oil recovery, waste water treatment, and so forth. For example, due to the high w/o interface activity of surfactants such as heavy alkyl benzene sulfonate (HABS) and petroleum sulfonate, severe emulsion has also been found with the alkali-surfactant-polymer (ASP) produced fluid. Currently, rapid breaking of these emulsion fluid is still a big challenge.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78195814","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}
Scale inhibitor (SI) analysis is an extremely important part of scale management and, in recent years, much work has been done on the development of specialist scale inhibitor analysis techniques like Liquid Chromatography Mass Spectroscopy (LCMS) to push the boundaries of low level scale inhibitor detection. However, LCMS requires costly and complex instrumentation and there was therefore still a need for the development of other advanced techniques like fluorescence (F) and Time resolved Fluorescence (TRF) that can be used on site to provide near "on line" data. Fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules like polyamines whereas the operation principle of TRF is based on interactions between lanthanide ions and various functional groups of polymer or phosphonate scale inhibitors. Both techniques work individually or in combination and this provides a distinct advantage for multiple scale inhibitor analysis in produced brines that enable the design of packages of different products for specific field applications. In addition, TRF and fluorescence techniques offer the capability of on-site detection compared to the majority of scale inhibitor analysis techniques and other advanced methods like LC-MS. The ability to detect both phosphonate and polymeric scale inhibitors at very low MIC (<1ppm) has the potential for significantly extending scale squeeze lifetimes. This has now also allowed highly efficient, F tagged polymers, to be used in field situations where scale squeezing was either stopped or the lifetime was significantly compromised because of the lack of confidence in the residuals analysis. Specific field and theoretical examples from both sub-sea and conventional wells will be presented where the application of both advanced fluorescence and TRF techniques has shown significant improvements in scale management. This paper will compare and contrast the pros, cons and limitations of both fluorescence and TRF techniques for both phosphonate and polymeric scale inhibitors. In addition, it will highlight examples where scale management significantly improves through the application of Fluorescence and/or TRF scale inhibitor analysis techniques in complex production scenarios.
{"title":"Application of Advanced Fluorescence Detection Technology to Improve Scale Management in Both Conventional and Sub-Sea Fields","authors":"S. Heath, S. Toivonen, V. Vuori, Salla Puupponen","doi":"10.2118/193632-MS","DOIUrl":"https://doi.org/10.2118/193632-MS","url":null,"abstract":"\u0000 Scale inhibitor (SI) analysis is an extremely important part of scale management and, in recent years, much work has been done on the development of specialist scale inhibitor analysis techniques like Liquid Chromatography Mass Spectroscopy (LCMS) to push the boundaries of low level scale inhibitor detection. However, LCMS requires costly and complex instrumentation and there was therefore still a need for the development of other advanced techniques like fluorescence (F) and Time resolved Fluorescence (TRF) that can be used on site to provide near \"on line\" data.\u0000 Fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules like polyamines whereas the operation principle of TRF is based on interactions between lanthanide ions and various functional groups of polymer or phosphonate scale inhibitors.\u0000 Both techniques work individually or in combination and this provides a distinct advantage for multiple scale inhibitor analysis in produced brines that enable the design of packages of different products for specific field applications. In addition, TRF and fluorescence techniques offer the capability of on-site detection compared to the majority of scale inhibitor analysis techniques and other advanced methods like LC-MS.\u0000 The ability to detect both phosphonate and polymeric scale inhibitors at very low MIC (<1ppm) has the potential for significantly extending scale squeeze lifetimes. This has now also allowed highly efficient, F tagged polymers, to be used in field situations where scale squeezing was either stopped or the lifetime was significantly compromised because of the lack of confidence in the residuals analysis.\u0000 Specific field and theoretical examples from both sub-sea and conventional wells will be presented where the application of both advanced fluorescence and TRF techniques has shown significant improvements in scale management.\u0000 This paper will compare and contrast the pros, cons and limitations of both fluorescence and TRF techniques for both phosphonate and polymeric scale inhibitors. In addition, it will highlight examples where scale management significantly improves through the application of Fluorescence and/or TRF scale inhibitor analysis techniques in complex production scenarios.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88011175","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}
Xin Wang, Saebom Ko, Ya Liu, A. Lu, Yue Zhao, K. Harouaka, Guannan Deng, Samridhdi Paudyal, Chong Dai, A. Kan, M. Tomson
Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H2S corrosion rate.
{"title":"Kinetics and Thermodynamics of Iron Sulfide, Precipitation, Deposition and Control","authors":"Xin Wang, Saebom Ko, Ya Liu, A. Lu, Yue Zhao, K. Harouaka, Guannan Deng, Samridhdi Paudyal, Chong Dai, A. Kan, M. Tomson","doi":"10.2118/193630-MS","DOIUrl":"https://doi.org/10.2118/193630-MS","url":null,"abstract":"\u0000 Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H2S corrosion rate.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76569717","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}
Ma Yingxian, Ma Leyao, Jianchun Guo, J. Lai, Han Zhou, Jia Li
We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via one-pot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 °C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.
{"title":"A High Temperature and Salt Resistance Supramolecular Thickening System","authors":"Ma Yingxian, Ma Leyao, Jianchun Guo, J. Lai, Han Zhou, Jia Li","doi":"10.2118/193549-MS","DOIUrl":"https://doi.org/10.2118/193549-MS","url":null,"abstract":"\u0000 We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via one-pot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 °C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80010527","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}
Organic functionalities have attached with layered materials through weak ionic bonds in traditional viscosifiers. Since the ionic linkages are weaker than the covalent bonds, ionic organic functionalities tend to detach under high temperature, pressure, shears, presence of other stronger ionic groups and repeated exposures toward alkaline or acidic conditions. To overcome these drawbacks of traditional viscosifiers, we have designed a novel viscosifier with covalently-linked organic moieties on layered materials (COLM). The organic functionalities were linked on the nano-platelets through covalent bonding and thus these linkages provide excellent stability compare to ionic interaction. The synthesis of COLM involves facile synthetic routes that have generated synthetic layered materials of high purity and reproducible chemical composition. The rheological properties of oil-based mud (OBM) containing COLM are characterized under high temperature and high pressure. Unprecedented flat rheology was observed when COLM was blended in OBM and compared with traditional organoclay. The temperature dependent viscoelastic behavior (storage modulus, G' and loss modulus, G") of the OBMs were also studied to establish the effectiveness of COLM compare to traditional organoclay.
{"title":"Covalently-Linked Organic Functionalities on Nano-Platelets as a Viscosifier for Oil-Based Muds","authors":"Hasmukh A. Patel, A. Santra, Carl J. Thaemlitz","doi":"10.2118/193588-MS","DOIUrl":"https://doi.org/10.2118/193588-MS","url":null,"abstract":"\u0000 Organic functionalities have attached with layered materials through weak ionic bonds in traditional viscosifiers. Since the ionic linkages are weaker than the covalent bonds, ionic organic functionalities tend to detach under high temperature, pressure, shears, presence of other stronger ionic groups and repeated exposures toward alkaline or acidic conditions. To overcome these drawbacks of traditional viscosifiers, we have designed a novel viscosifier with covalently-linked organic moieties on layered materials (COLM). The organic functionalities were linked on the nano-platelets through covalent bonding and thus these linkages provide excellent stability compare to ionic interaction. The synthesis of COLM involves facile synthetic routes that have generated synthetic layered materials of high purity and reproducible chemical composition. The rheological properties of oil-based mud (OBM) containing COLM are characterized under high temperature and high pressure. Unprecedented flat rheology was observed when COLM was blended in OBM and compared with traditional organoclay. The temperature dependent viscoelastic behavior (storage modulus, G' and loss modulus, G\") of the OBMs were also studied to establish the effectiveness of COLM compare to traditional organoclay.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"2016 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82926317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Wei, Yuanyuan Wang, Chen Shengen, Runxue Mao, Jianyuan Ning, Wanlu Wang
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
{"title":"Relation Between Chemical Composition of a Green Nanofluid and Its Foam Film Stabilization For Robust Foam Injection EOR","authors":"B. Wei, Yuanyuan Wang, Chen Shengen, Runxue Mao, Jianyuan Ning, Wanlu Wang","doi":"10.2118/193633-MS","DOIUrl":"https://doi.org/10.2118/193633-MS","url":null,"abstract":"\u0000 Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81516001","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}
Abdullah M. Al Moajil, S. Çalışkan, A. Al-Salem, I. Al-Yami
Carbonate reservoir matrix acidizing is commonly conducted with HCl. In these treatments, HCl acid is used to create conductive channels (wormholes) to enhance well productivity/injectivity. However, its use has been limited due to associated rapid tubulars corrosion and formation face dissolution, especially in deep hot reservoirs. Emulsified acid was used as an effective alternative to HCl, but it is associated with drawbacks such high friction losses and emulsion stability. In this paper, an aqueous single-phase retarded HCl alternative system was evaluated as an alternative to straight and emulsified acid fluids. Coreflood experiments were conducted using Indiana limestone core plugs at 180 and 270°F. Computerized Tomography (CT) scan analysis was conducted on the core plugs before/after coreflood testing. Compatibility testing was conducted on prepared retarder acid recipes. ESEM, TGA, and ICP analysis was used to analyze prepared retarder acid recipes and associated solids. Turbiscan LAB was used to assess the stability of the retarded acid recipes. The low pore volume to breakthrough (PVBT) values (i.e., 0.9-1.6) obtained from coreflood testing at 180 and 270°F, confirmed the retarded HCl acid recipes were effective to stimulate carbonate reservoirs. Compatibility testing showed presence of significant white precipitate. ESEM analysis showed the precipitates were rod-like crystals composed of mainly of Cl and high C with small amounts of N, O, Al and Mg. TGA results showed the major constituent of precipitate were organic-based materials. The precipitate was mainly H4EDTA and chloride. Despite presence of white precipitate at the core inlet, the effect on the performance of the retarded acid system was insignificant. CT scanning analysis of the plug samples before/after the coreflooding experiments showed that wormholes along the plug length with multiple branches were formed in all cases indicating the compatibility of the selected acid recipe.
{"title":"Aqueous Alternative System to Straight and Emulsified HCl Acids for Carbonate Acidizing","authors":"Abdullah M. Al Moajil, S. Çalışkan, A. Al-Salem, I. Al-Yami","doi":"10.2118/193551-MS","DOIUrl":"https://doi.org/10.2118/193551-MS","url":null,"abstract":"\u0000 Carbonate reservoir matrix acidizing is commonly conducted with HCl. In these treatments, HCl acid is used to create conductive channels (wormholes) to enhance well productivity/injectivity. However, its use has been limited due to associated rapid tubulars corrosion and formation face dissolution, especially in deep hot reservoirs. Emulsified acid was used as an effective alternative to HCl, but it is associated with drawbacks such high friction losses and emulsion stability. In this paper, an aqueous single-phase retarded HCl alternative system was evaluated as an alternative to straight and emulsified acid fluids.\u0000 Coreflood experiments were conducted using Indiana limestone core plugs at 180 and 270°F. Computerized Tomography (CT) scan analysis was conducted on the core plugs before/after coreflood testing. Compatibility testing was conducted on prepared retarder acid recipes. ESEM, TGA, and ICP analysis was used to analyze prepared retarder acid recipes and associated solids. Turbiscan LAB was used to assess the stability of the retarded acid recipes.\u0000 The low pore volume to breakthrough (PVBT) values (i.e., 0.9-1.6) obtained from coreflood testing at 180 and 270°F, confirmed the retarded HCl acid recipes were effective to stimulate carbonate reservoirs. Compatibility testing showed presence of significant white precipitate. ESEM analysis showed the precipitates were rod-like crystals composed of mainly of Cl and high C with small amounts of N, O, Al and Mg. TGA results showed the major constituent of precipitate were organic-based materials. The precipitate was mainly H4EDTA and chloride. Despite presence of white precipitate at the core inlet, the effect on the performance of the retarded acid system was insignificant. CT scanning analysis of the plug samples before/after the coreflooding experiments showed that wormholes along the plug length with multiple branches were formed in all cases indicating the compatibility of the selected acid recipe.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76497355","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}
Five different variants of the acrylamidotertiary-butyl sulfonic acid (ATBS) / N,N-dimethylacrylamide (NNDMA) copolymer were examined and evaluated, comparing their mixability and fluid-loss performance. These were characterized using gel permeation chromatography equipped with multi-angle laser light scattering (GPC-MALLS) and viscometry to evaluate the effects of number average molecular weight (Mn), radius of gyration (Rg), dispersity (Đ), and viscosity values in water and cement. It was determined that there was an optimum Đ value at which the mixability performance of the cement slurry formulated with the fluid loss copolymer was achieved. Additionally, it was determined that an increase in Đ improved fluid loss performance for a given Mn and Rg. More interestingly, an increase in Rg at fixed Mn and Đ decreases fluid-loss performance, which is counterintuitive to the particle bridging mechanism. A quantitative relationship between the copolymer characteristics and its fluid-loss performance was determined. Understanding the relationship between structure and function of 2-acrylamido-2-methylpropane sulfonic acid-NNDMA copolymers in a cement slurry is the first step toward designing fluid-loss additives with targeted properties.
{"title":"Relationship Between the 2-acrylamido-2-methylpropane Sulfonic Acid–NNDMA Copolymer Properties and Fluid Loss and Mixability in Cementing Fluids","authors":"William C. Pearl, S. Lewis, J. P. Singh","doi":"10.2118/193537-MS","DOIUrl":"https://doi.org/10.2118/193537-MS","url":null,"abstract":"\u0000 Five different variants of the acrylamidotertiary-butyl sulfonic acid (ATBS) / N,N-dimethylacrylamide (NNDMA) copolymer were examined and evaluated, comparing their mixability and fluid-loss performance. These were characterized using gel permeation chromatography equipped with multi-angle laser light scattering (GPC-MALLS) and viscometry to evaluate the effects of number average molecular weight (Mn), radius of gyration (Rg), dispersity (Đ), and viscosity values in water and cement.\u0000 It was determined that there was an optimum Đ value at which the mixability performance of the cement slurry formulated with the fluid loss copolymer was achieved. Additionally, it was determined that an increase in Đ improved fluid loss performance for a given Mn and Rg. More interestingly, an increase in Rg at fixed Mn and Đ decreases fluid-loss performance, which is counterintuitive to the particle bridging mechanism.\u0000 A quantitative relationship between the copolymer characteristics and its fluid-loss performance was determined. Understanding the relationship between structure and function of 2-acrylamido-2-methylpropane sulfonic acid-NNDMA copolymers in a cement slurry is the first step toward designing fluid-loss additives with targeted properties.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"122 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76987888","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 variety and sophistication of upstream technologies have been growing fast for imaging the subsurface, modeling reservoir performance and monitoring oil and gas production. Yet there remains a fundamental need to thoroughly sample and analyze the produced reservoir fluids. Reservoir fluid analysis is critical for understanding the nature of produced hydrocarbons and is the key for production optimization. To gain the maximum value from this analysis, reservoir fluid sampling programs need to be well designed and integrated into well testing and reservoir surveillance programs, and not to be developed after. In one of Chevron's deep-water Gulf of Mexico (DWGOM) sub-salt fields, a robust geochemical sampling plan and production monitoring program has been in place since initial production to estimate the zonal contribution from individually stacked reservoirs. This surveillance work has been ongoing for 9 commingled wells over a period of 10 years. This paper presents the accuracy of time lapsed production geochemistry allocation and how the results can substantially impact and improve reservoir characterization and trouble shoot completion issues
{"title":"Time Lapse Production Allocation Using Oil Fingerprinting for Production Optimization in Deepwater Gulf Mexico","authors":"L. Xing, S. Teerman, F. Descant","doi":"10.2118/193601-MS","DOIUrl":"https://doi.org/10.2118/193601-MS","url":null,"abstract":"\u0000 The variety and sophistication of upstream technologies have been growing fast for imaging the subsurface, modeling reservoir performance and monitoring oil and gas production. Yet there remains a fundamental need to thoroughly sample and analyze the produced reservoir fluids. Reservoir fluid analysis is critical for understanding the nature of produced hydrocarbons and is the key for production optimization. To gain the maximum value from this analysis, reservoir fluid sampling programs need to be well designed and integrated into well testing and reservoir surveillance programs, and not to be developed after.\u0000 In one of Chevron's deep-water Gulf of Mexico (DWGOM) sub-salt fields, a robust geochemical sampling plan and production monitoring program has been in place since initial production to estimate the zonal contribution from individually stacked reservoirs.\u0000 This surveillance work has been ongoing for 9 commingled wells over a period of 10 years. This paper presents the accuracy of time lapsed production geochemistry allocation and how the results can substantially impact and improve reservoir characterization and trouble shoot completion issues","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74275502","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}
It is well known within the industry that conventional drilling fluids can damage the well's producing zone. Damage mechanisms occur due to leakage of drilling fluid into the formation even after the formation of a filter cake. This filtrate contains entrained particulates that can enter the pore spaces of the rock and restrict flow through the pore throats resulting in reduced permeability during production. Cleaner drill-in fluids with low solids content have been developed for use when drilling through a producing zone in an attempt to mitigate the extent of damage caused by leak-off. These fluids should not only provide excellent fluid loss prevention, but also exhibit the rheological characteristics needed to perform the traditional functions of conventional fluids. Even though these fluids reduce the amount of particulates entering the formation by containing less solids, the filtrate that is still able to flow through the filter cake can be equally as damaging. Reduction of filtrate volumes can be further achieved by introducing nanoparticles to bridge across the nano-sized gaps within the filter cake. This research focuses on the application of polyelectrolyte complex nanoparticles (PECNP) as a fluid loss additive to further enhance the filter cake filtration properties of a general drill-in fluid. A baseline fluid is formulated consisting of a sodium chloride brine, biopolymers for rheology and fluid loss purposes, and calcium carbonate as a density and bridging agent. The ratio and pH of polyelectrolytes were optimized in order to create stable PECNPs for this system. Different dilutions of PECNPs were added and tested in a static fluid loss setup, where filtrate volumes were compared to determine the best system of 1/8th diluted nanoparticles. The chosen system was then taken to be tested in the dynamic fluid loss setup "Quasimodo" where fluid loss volumes were successfully reduced and wall building coefficients lowered. Analysis of cleanup curves after testing revealed that the PECNP drill-in fluid was less damaging to the core permeability than when the baseline fluid was used.
{"title":"Water-Based Drill-In Fluid Optimization Using Polyelectrolyte Complex Nanoparticles as a Fluid Loss Additive","authors":"Lucas Whatley, R. Barati, Zach Kessler, J. Tsau","doi":"10.2118/193544-MS","DOIUrl":"https://doi.org/10.2118/193544-MS","url":null,"abstract":"\u0000 It is well known within the industry that conventional drilling fluids can damage the well's producing zone. Damage mechanisms occur due to leakage of drilling fluid into the formation even after the formation of a filter cake. This filtrate contains entrained particulates that can enter the pore spaces of the rock and restrict flow through the pore throats resulting in reduced permeability during production. Cleaner drill-in fluids with low solids content have been developed for use when drilling through a producing zone in an attempt to mitigate the extent of damage caused by leak-off. These fluids should not only provide excellent fluid loss prevention, but also exhibit the rheological characteristics needed to perform the traditional functions of conventional fluids. Even though these fluids reduce the amount of particulates entering the formation by containing less solids, the filtrate that is still able to flow through the filter cake can be equally as damaging. Reduction of filtrate volumes can be further achieved by introducing nanoparticles to bridge across the nano-sized gaps within the filter cake. This research focuses on the application of polyelectrolyte complex nanoparticles (PECNP) as a fluid loss additive to further enhance the filter cake filtration properties of a general drill-in fluid. A baseline fluid is formulated consisting of a sodium chloride brine, biopolymers for rheology and fluid loss purposes, and calcium carbonate as a density and bridging agent. The ratio and pH of polyelectrolytes were optimized in order to create stable PECNPs for this system. Different dilutions of PECNPs were added and tested in a static fluid loss setup, where filtrate volumes were compared to determine the best system of 1/8th diluted nanoparticles. The chosen system was then taken to be tested in the dynamic fluid loss setup \"Quasimodo\" where fluid loss volumes were successfully reduced and wall building coefficients lowered. Analysis of cleanup curves after testing revealed that the PECNP drill-in fluid was less damaging to the core permeability than when the baseline fluid was used.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74879957","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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