Ashok Santra, Hasmukh A. Patel, Sivaprakash Shanmugam
The rheological properties of drilling fluids are crucial parameters for efficient drilling operations. Invert emulsion drilling fluids are the industry's preferred choice when it comes to extreme conditions like deepwater or high temperature and high pressure (HTHP) drilling due to their inherent thermal stability and effectiveness against water sensitive formations. In addition, another highly desired property of such drilling fluids is minimal sensitivity of the fluid flow properties for a wide range of application temperatures, known as flat-rheology behavior. We have developed four novel and next generation chemical additives: (i) a high temperature stable emulsifier, (ii) a low-end rheology modifier, (iii) a viscosifier with covalently linked organic groups, and (iv) a fluid loss control additive. Molecular architectural designs and synthesis of all four chemicals were carried out in our laboratory and used in optimum quantities to build industry's next generation invert emulsion fluids at density ranges from 75 – 135pcf (10-18ppg) and application temperature range of 60-450°F. Rheological and other important drilling fluid properties were tested at different downhole pressures and temperatures using a standard API recommended HTHP apparatus. The results demonstrated extreme thermal stability all the way from 60-450°F with excellent fluid loss control and ultrathin filter cake. The novel covalently-linked organophilic viscosifier used herein has proven superior thermal stability compared to existing organo-clay based systems especially at temperatures above 350°F. Novel secondary emulsifier and low-end rheology modifier have demonstrated excellent emulsion stability at temperatures up to 450°F. It has been an industry challenge to obtain true flat rheological behavior under high pressure and temperature using commercially available chemistries. However, very interestingly, fluids optimized in this work have exhibited excellent flat-rheological behavior for a wide range of temperatures. We will present a comparative analysis of the relationship between molecular structure and properties perspective of what is currently used in the industry versus those developed in this work. The current work has led to development of four novel chemical additives which are responsible for the industry's next generation high performance invert emulsion drilling fluids with flat-rheological behavior.
{"title":"Next Generation High Performance Invert Emulsion Drilling Fluids with Flat-Rheological Behavior","authors":"Ashok Santra, Hasmukh A. Patel, Sivaprakash Shanmugam","doi":"10.2118/204285-ms","DOIUrl":"https://doi.org/10.2118/204285-ms","url":null,"abstract":"\u0000 The rheological properties of drilling fluids are crucial parameters for efficient drilling operations. Invert emulsion drilling fluids are the industry's preferred choice when it comes to extreme conditions like deepwater or high temperature and high pressure (HTHP) drilling due to their inherent thermal stability and effectiveness against water sensitive formations. In addition, another highly desired property of such drilling fluids is minimal sensitivity of the fluid flow properties for a wide range of application temperatures, known as flat-rheology behavior.\u0000 We have developed four novel and next generation chemical additives: (i) a high temperature stable emulsifier, (ii) a low-end rheology modifier, (iii) a viscosifier with covalently linked organic groups, and (iv) a fluid loss control additive. Molecular architectural designs and synthesis of all four chemicals were carried out in our laboratory and used in optimum quantities to build industry's next generation invert emulsion fluids at density ranges from 75 – 135pcf (10-18ppg) and application temperature range of 60-450°F. Rheological and other important drilling fluid properties were tested at different downhole pressures and temperatures using a standard API recommended HTHP apparatus.\u0000 The results demonstrated extreme thermal stability all the way from 60-450°F with excellent fluid loss control and ultrathin filter cake. The novel covalently-linked organophilic viscosifier used herein has proven superior thermal stability compared to existing organo-clay based systems especially at temperatures above 350°F. Novel secondary emulsifier and low-end rheology modifier have demonstrated excellent emulsion stability at temperatures up to 450°F. It has been an industry challenge to obtain true flat rheological behavior under high pressure and temperature using commercially available chemistries. However, very interestingly, fluids optimized in this work have exhibited excellent flat-rheological behavior for a wide range of temperatures. We will present a comparative analysis of the relationship between molecular structure and properties perspective of what is currently used in the industry versus those developed in this work.\u0000 The current work has led to development of four novel chemical additives which are responsible for the industry's next generation high performance invert emulsion drilling fluids with flat-rheological behavior.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"140 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77590800","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 effects of elemental sulfur on the corrosion of mild steel is a serious problem in the oil & gas industry costing millions of dollars annually in lost production and assets. Mitigating the corrosive effects of elemental sulfur on mild steel in the oil and gas industry is a challenge and finding a viable solution would provide a more cost effective and safer working environment and as well as be environmentally conscious. Currently, there are no highly effective products for elemental sulfur corrosion in the marketplace. More than fifty new chemical formulations were blended and screened by rotating cylinder electrode method (RCE). These formulations were tested in the presence of 0.1% elemental sulfur in mildly sour conditions. The promising candidates were identified and tested again in the presence of elemental sulfur under the same mildly sour conditions. The most promising candidates from the initial screening were then subjected to rotating cage autoclave (RCA) testing for extended periods of time in the presence of 0.1% and 0.15% elemental sulfur. The general corrosion rates were calculated via weight loss and the metal surfaces were examined under a high-power digital microscope for pitting and localized corrosion. A detailed analysis of the above testing yields promising results. The results from the testing show that formulations mitigate pitting in environments containing elemental sulfur. In less harsh conditions, such as low chloride brines or low CO2 environment, formulations seem to provide excellent protection against general corrosion while mitigating pitting due to elemental sulfur. In more extreme environments such as harsh brines with elevated chloride levels, high hydrogen sulfide and CO2 levels, the formulations mitigate pitting but need further development in inhibiting general corrosion The best product currently developed inhibits corrosion and pitting in the presence of elemental sulfur in various conditions and performs well against elemental sulfur in more aggressive sour systems. We are currently improving the performance against elemental sulfur and developing chemistries to mitigate polysulfide induced corrosion in sour systems. This paper describes the development of effective inhibitors for corrosion and pitting in the presence of elemental sulfur under sour conditions. This study focuses more on pitting corrosion due to the corrosive characteristics of elemental sulfur than on uniform general corrosion. The general corrosion with the selected inhibitor was highly mitigated and was less than 3.0 mpy while yielding excellent protection against sulfur induced pitting.
{"title":"Development of Corrosion Inhibitors to Mitigate Elemental Sulfur Induced Pitting Corrosion","authors":"Douglas C. Dickey, N. Obeyesekere, J. Wylde","doi":"10.2118/204307-ms","DOIUrl":"https://doi.org/10.2118/204307-ms","url":null,"abstract":"\u0000 The effects of elemental sulfur on the corrosion of mild steel is a serious problem in the oil & gas industry costing millions of dollars annually in lost production and assets.\u0000 Mitigating the corrosive effects of elemental sulfur on mild steel in the oil and gas industry is a challenge and finding a viable solution would provide a more cost effective and safer working environment and as well as be environmentally conscious. Currently, there are no highly effective products for elemental sulfur corrosion in the marketplace.\u0000 More than fifty new chemical formulations were blended and screened by rotating cylinder electrode method (RCE). These formulations were tested in the presence of 0.1% elemental sulfur in mildly sour conditions. The promising candidates were identified and tested again in the presence of elemental sulfur under the same mildly sour conditions.\u0000 The most promising candidates from the initial screening were then subjected to rotating cage autoclave (RCA) testing for extended periods of time in the presence of 0.1% and 0.15% elemental sulfur. The general corrosion rates were calculated via weight loss and the metal surfaces were examined under a high-power digital microscope for pitting and localized corrosion.\u0000 A detailed analysis of the above testing yields promising results. The results from the testing show that formulations mitigate pitting in environments containing elemental sulfur. In less harsh conditions, such as low chloride brines or low CO2 environment, formulations seem to provide excellent protection against general corrosion while mitigating pitting due to elemental sulfur. In more extreme environments such as harsh brines with elevated chloride levels, high hydrogen sulfide and CO2 levels, the formulations mitigate pitting but need further development in inhibiting general corrosion The best product currently developed inhibits corrosion and pitting in the presence of elemental sulfur in various conditions and performs well against elemental sulfur in more aggressive sour systems. We are currently improving the performance against elemental sulfur and developing chemistries to mitigate polysulfide induced corrosion in sour systems.\u0000 This paper describes the development of effective inhibitors for corrosion and pitting in the presence of elemental sulfur under sour conditions. This study focuses more on pitting corrosion due to the corrosive characteristics of elemental sulfur than on uniform general corrosion. The general corrosion with the selected inhibitor was highly mitigated and was less than 3.0 mpy while yielding excellent protection against sulfur induced pitting.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"1 4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78252078","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}
CO2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate–rich aquifers, CO2 dissolves in the formation brine under the large pressure, and the subsequently formed CO2–enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO2storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO2–enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO2 sealing capacity and guarantee environmental security.
{"title":"Pore–Scale Numerical Investigations of the Impact of Mineral Dissolution and Transport in Naturally Fractured Systems During CO2–Enriched Brine Injection","authors":"Jiahui You, K. Lee","doi":"10.2118/204313-ms","DOIUrl":"https://doi.org/10.2118/204313-ms","url":null,"abstract":"\u0000 CO2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate–rich aquifers, CO2 dissolves in the formation brine under the large pressure, and the subsequently formed CO2–enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO2storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO2–enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO2 sealing capacity and guarantee environmental security.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79833559","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}
Khawlah Alanqari, V. Wagle, A. Al-Yami, Ali Mohammed
The novel resin composition described in this paper has been designed to treat moderate to severe losses. The resin composition comprises an epoxy resin and a chemical activator that undergo a polymerization reaction without any addition of water. The polymerization was designed to delay and successfully controlled to gel up and form the target resin composition after the fluid goes inside the wellbore. This is very important to avoid early setting of the fluid. The objective of this paper is to discuss the formulation of epoxy resin as a lost circulation material and also detail the lab testing and field execution. In this study, we used two different epoxy resins to study the development of the novel loss circulation material. One contains two epoxy groups and the other contains only one epoxy group. Two different chemical activators have been used in this study as well; each of them differs in the number of amine groups and geometry. The effect of these differences on the polymerization in terms of time and properties were investigated. In addition, the effect of the chemical activator concertation on the setting time of the resin composition was investigated to accomplish a controlled and a delayed polymerization. Also, the chemical conditions were evaluated to simulate a variety of downhole conditions to prove the effectiveness of this novel resin composition as a loss circulation treatment. The lab testing includes thickening time measurements. The novel resin composition is designed to have a controlled thickening time under a variety of downhole conditions. This is important to have an accurate placement of the fluid inside the wellbore; thus, avoiding an early setting of the fluid. We found that the thickening time of the resin composition can be controlled by mainly varying the concertation of the chemical activator. We found as well that changing the type of epoxy resin or chemical activator produce different gelling time and properties. We designed the loss circulation composition to provide a predictable and controlled pumping time. This novel resin composition can remain in a liquid phase from a few minutes to several hours based on the desired conditions. This is favorable in order to have an accurate placement of the fluid inside the wellbore over a predictable and controlled period of time. The final and target resin composition, will appear and gel as a solid thereby preventing loss circulation. The resin was pumped from the BHA in a single stage which helped mitigate and reduce the dynamic losses from 260 bbl./hr. to 200 bbl./hr. using only 25 bbls and eventually to zero.
{"title":"A Novel Epoxy Resin Composition as a Lost Circulation Material: Formulation, Lab Testing and Field Execution","authors":"Khawlah Alanqari, V. Wagle, A. Al-Yami, Ali Mohammed","doi":"10.2118/204301-ms","DOIUrl":"https://doi.org/10.2118/204301-ms","url":null,"abstract":"\u0000 The novel resin composition described in this paper has been designed to treat moderate to severe losses. The resin composition comprises an epoxy resin and a chemical activator that undergo a polymerization reaction without any addition of water. The polymerization was designed to delay and successfully controlled to gel up and form the target resin composition after the fluid goes inside the wellbore. This is very important to avoid early setting of the fluid. The objective of this paper is to discuss the formulation of epoxy resin as a lost circulation material and also detail the lab testing and field execution.\u0000 In this study, we used two different epoxy resins to study the development of the novel loss circulation material. One contains two epoxy groups and the other contains only one epoxy group. Two different chemical activators have been used in this study as well; each of them differs in the number of amine groups and geometry. The effect of these differences on the polymerization in terms of time and properties were investigated. In addition, the effect of the chemical activator concertation on the setting time of the resin composition was investigated to accomplish a controlled and a delayed polymerization. Also, the chemical conditions were evaluated to simulate a variety of downhole conditions to prove the effectiveness of this novel resin composition as a loss circulation treatment. The lab testing includes thickening time measurements.\u0000 The novel resin composition is designed to have a controlled thickening time under a variety of downhole conditions. This is important to have an accurate placement of the fluid inside the wellbore; thus, avoiding an early setting of the fluid. We found that the thickening time of the resin composition can be controlled by mainly varying the concertation of the chemical activator. We found as well that changing the type of epoxy resin or chemical activator produce different gelling time and properties. We designed the loss circulation composition to provide a predictable and controlled pumping time. This novel resin composition can remain in a liquid phase from a few minutes to several hours based on the desired conditions. This is favorable in order to have an accurate placement of the fluid inside the wellbore over a predictable and controlled period of time. The final and target resin composition, will appear and gel as a solid thereby preventing loss circulation.\u0000 The resin was pumped from the BHA in a single stage which helped mitigate and reduce the dynamic losses from 260 bbl./hr. to 200 bbl./hr. using only 25 bbls and eventually to zero.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74717867","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}
Ahmed H. El-Kady, Zheng-Qi Chai, Hisham A. Nasr-El-Din
Aminopolycarboxylate-based chelants are used to control iron precipitation during acidizing operations by interacting directly with the iron, resulting in water-soluble complexes. This paper highlights that, in order to improve the effectiveness of iron control during acidizing operations, the type and the concentration of the chelants should be based on the formation properties and the well characteristics by comparing the cheltors’ performance as iron-control agents at different temperatures and pH environments with different levels of iron concentrations and chelant to iron molar ratios in acid (HCl). This study also addresses the interactions between the tested iron-control additives and acid, as well as the performance of the chelants in carbonate cores. Laboratory experiments were conducted to investigate the performance of nitrilotriacetic acid (NTA), glutamic acid, N, N-diacetic acid (GLDA), diethylenetriaminepentaacetic acid (DTPA), ethylenediamine-tetraacetic acid (EDTA), and hydroxyethylethylenediaminetriacetic acid (HEDTA) as iron control additives in 5 wt% HCl at pH values 0 to 4.5 to simulate carbonate acidizing at temperatures of 70 to 300°F, and initial iron concentrations of 2000 ppm. The performance of NTA and EDTA was also compared at higher initial iron concentration (4000 ppm). This work also quantified the effects of acid additives such as corrosion inhibitor and non-ionic surfactant on the chelation performance. Coreflood experiments using carbonate cores in acid with chelant helped determine its influence on permeability. Testing chelant-to-acid molar ratios of 1:1, 1.1:1, 1.2:1, 1.3:1, 1.4:1, 1.5:1, and 2:1 relative to iron concentration yielded optimal values. Additional tests monitored iron precipitation in solution using an inductively coupled argon plasma (ICAP) emission spectroscopy. Precipitates were filtered and analyzed using X-ray diffraction (XRD), X-ray fluorescence (XRF), and scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS). Without chelant, at 70°F and 2000 ppm initial iron concentration, precipitation began at pH 1.45 and completed by pH 2.42. At 150 and 210°F, iron precipitated at pH 0.68 and 0.3 and completed by pH 1.3 and 1, respectively. At 70°F, NTA showed a minimum of 98% chelation at pH 4.3; however, its performance declined at 150°F to 74% chelation at pH 4.24, and at 210°F to 53% chelation at pH 4.0. Although DTPA dissolves completely in live acid, precipitations occurred at partially spent acid. At pH 0.15, SEM-EDS showed that the precipitate contains as much as 13 wt% iron. Thus, DTPA is not a suitable iron-control agent. HEDTA showed a 90% chelation at 210°F and pH 4.8. GLDA's performance declined to less than 50% at 150°F. At higher iron concentrations of 4000 ppm, Na3NTA kept all iron in solution in a 5 wt% HCl up to pH 4.0 at 70°F and its performance declined to a minimum of 97% at pH 4.7 at same temperature. At 150°F, and 210°F, Na3NTA started to gradually decline at
{"title":"Comparative Analysis of Aminopolycarboxylate Chelants Improves Iron Control in Acidizing Operations","authors":"Ahmed H. El-Kady, Zheng-Qi Chai, Hisham A. Nasr-El-Din","doi":"10.2118/204322-ms","DOIUrl":"https://doi.org/10.2118/204322-ms","url":null,"abstract":"\u0000 Aminopolycarboxylate-based chelants are used to control iron precipitation during acidizing operations by interacting directly with the iron, resulting in water-soluble complexes. This paper highlights that, in order to improve the effectiveness of iron control during acidizing operations, the type and the concentration of the chelants should be based on the formation properties and the well characteristics by comparing the cheltors’ performance as iron-control agents at different temperatures and pH environments with different levels of iron concentrations and chelant to iron molar ratios in acid (HCl). This study also addresses the interactions between the tested iron-control additives and acid, as well as the performance of the chelants in carbonate cores.\u0000 Laboratory experiments were conducted to investigate the performance of nitrilotriacetic acid (NTA), glutamic acid, N, N-diacetic acid (GLDA), diethylenetriaminepentaacetic acid (DTPA), ethylenediamine-tetraacetic acid (EDTA), and hydroxyethylethylenediaminetriacetic acid (HEDTA) as iron control additives in 5 wt% HCl at pH values 0 to 4.5 to simulate carbonate acidizing at temperatures of 70 to 300°F, and initial iron concentrations of 2000 ppm. The performance of NTA and EDTA was also compared at higher initial iron concentration (4000 ppm). This work also quantified the effects of acid additives such as corrosion inhibitor and non-ionic surfactant on the chelation performance. Coreflood experiments using carbonate cores in acid with chelant helped determine its influence on permeability. Testing chelant-to-acid molar ratios of 1:1, 1.1:1, 1.2:1, 1.3:1, 1.4:1, 1.5:1, and 2:1 relative to iron concentration yielded optimal values. Additional tests monitored iron precipitation in solution using an inductively coupled argon plasma (ICAP) emission spectroscopy. Precipitates were filtered and analyzed using X-ray diffraction (XRD), X-ray fluorescence (XRF), and scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS).\u0000 Without chelant, at 70°F and 2000 ppm initial iron concentration, precipitation began at pH 1.45 and completed by pH 2.42. At 150 and 210°F, iron precipitated at pH 0.68 and 0.3 and completed by pH 1.3 and 1, respectively. At 70°F, NTA showed a minimum of 98% chelation at pH 4.3; however, its performance declined at 150°F to 74% chelation at pH 4.24, and at 210°F to 53% chelation at pH 4.0. Although DTPA dissolves completely in live acid, precipitations occurred at partially spent acid. At pH 0.15, SEM-EDS showed that the precipitate contains as much as 13 wt% iron. Thus, DTPA is not a suitable iron-control agent. HEDTA showed a 90% chelation at 210°F and pH 4.8. GLDA's performance declined to less than 50% at 150°F. At higher iron concentrations of 4000 ppm, Na3NTA kept all iron in solution in a 5 wt% HCl up to pH 4.0 at 70°F and its performance declined to a minimum of 97% at pH 4.7 at same temperature. At 150°F, and 210°F, Na3NTA started to gradually decline at ","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85158460","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}
Zhengwei Liu, Sankaran Murugesan, S. Ramachandran, Peng Jin
Accurate and precise monitoring of chemical additives in oilfield brine is an important aspect of oil and gas operations towards corrosion control and flow assurance. Many operators are required to monitor the residual concentrations of chemical additives in production systems at specific locations to monitor and troubleshoot factors affecting chemical deliverability and performance. However, residual measurements are extremely problematic due to many factors, including the surface active nature of the chemicals and high ionic strength of the brine. The error on residual measurements can often be over 100%. Residual measurement typically requires the collection of a water sample, which often needs to be transported to a centralized analytical laboratory. Analytical techniques used to measure residuals are based on several combinations of separation (e.g. chromatography, liquid-liquid extraction, etc.) and detection (e.g. various forms of spectroscopy). However, most of these methods lack portability and require tedious laboratory procedures located off-site. The current paper describes a nanotechnology-enabled Raman spectroscopy method developed and tested for monitoring chemical inhibitor residuals. Development of this technology with handheld instrumentation provides better detection and quantification of chemical additives in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.
{"title":"Next Generation Oilfield on-Site Trace Chemicals Analysis by SERS","authors":"Zhengwei Liu, Sankaran Murugesan, S. Ramachandran, Peng Jin","doi":"10.2118/204369-ms","DOIUrl":"https://doi.org/10.2118/204369-ms","url":null,"abstract":"\u0000 Accurate and precise monitoring of chemical additives in oilfield brine is an important aspect of oil and gas operations towards corrosion control and flow assurance. Many operators are required to monitor the residual concentrations of chemical additives in production systems at specific locations to monitor and troubleshoot factors affecting chemical deliverability and performance. However, residual measurements are extremely problematic due to many factors, including the surface active nature of the chemicals and high ionic strength of the brine. The error on residual measurements can often be over 100%. Residual measurement typically requires the collection of a water sample, which often needs to be transported to a centralized analytical laboratory. Analytical techniques used to measure residuals are based on several combinations of separation (e.g. chromatography, liquid-liquid extraction, etc.) and detection (e.g. various forms of spectroscopy). However, most of these methods lack portability and require tedious laboratory procedures located off-site. The current paper describes a nanotechnology-enabled Raman spectroscopy method developed and tested for monitoring chemical inhibitor residuals. Development of this technology with handheld instrumentation provides better detection and quantification of chemical additives in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"102 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86552317","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}
S. Lehrer, Jagrut Jani, S. Ramachandran, Zhengwei Liu
Currently used scavengers in mixed production applications can have issues with poor efficiency and thermal stability (triazines, glyoxal), scaling tendency (triazines), corrosivity (glyoxal), and emulsification (metal-based scavengers). Research was conducted which resulted in a new scavenger that avoids negative side effects while maintaining efficient performance over a wide range of applications. The application of this scavenger into mixed production can avoid or reduce the need for H2S removal post-separation, thereby reducing overall cost. The development and field application of a new Hydrogen Sulfide (H2S) Scavenger in oilfield mixed production applications is presented. Several field applications will be discussed comparing the overall performance of this new H2S scavenger with existing technologies. Field application results will show that this novel scavenger avoids issues with currently used scavengers including poor efficiency, corrosivity, scaling, and emulsification. This new H2S scavenger technology is suitable for both surface and downhole injection. It will be demonstrated how removing H2S upstream in mixed production can save overall treatment cost.
{"title":"Development and Application of a Novel Hydrogen Sulfide Scavenger for Oilfield Applications","authors":"S. Lehrer, Jagrut Jani, S. Ramachandran, Zhengwei Liu","doi":"10.2118/204311-ms","DOIUrl":"https://doi.org/10.2118/204311-ms","url":null,"abstract":"\u0000 Currently used scavengers in mixed production applications can have issues with poor efficiency and thermal stability (triazines, glyoxal), scaling tendency (triazines), corrosivity (glyoxal), and emulsification (metal-based scavengers). Research was conducted which resulted in a new scavenger that avoids negative side effects while maintaining efficient performance over a wide range of applications. The application of this scavenger into mixed production can avoid or reduce the need for H2S removal post-separation, thereby reducing overall cost.\u0000 The development and field application of a new Hydrogen Sulfide (H2S) Scavenger in oilfield mixed production applications is presented. Several field applications will be discussed comparing the overall performance of this new H2S scavenger with existing technologies. Field application results will show that this novel scavenger avoids issues with currently used scavengers including poor efficiency, corrosivity, scaling, and emulsification. This new H2S scavenger technology is suitable for both surface and downhole injection. It will be demonstrated how removing H2S upstream in mixed production can save overall treatment cost.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87776752","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}
K. Spicka, L. Holding Eagle, Chris Longie, K. Dahlgren, AJ Gerbino, A. Koerner, Greg Loder
The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (>90,000 mg/L), chloride (>200,000 mg/L), and calcium (>30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L). In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges. The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale. While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.
{"title":"Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility","authors":"K. Spicka, L. Holding Eagle, Chris Longie, K. Dahlgren, AJ Gerbino, A. Koerner, Greg Loder","doi":"10.2118/204358-ms","DOIUrl":"https://doi.org/10.2118/204358-ms","url":null,"abstract":"\u0000 The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (>90,000 mg/L), chloride (>200,000 mg/L), and calcium (>30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L).\u0000 In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges.\u0000 The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale.\u0000 While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83574337","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}
Martin Shumway, Ryan McGonagle, Anthony Nerris, J. I. Aguiar, A. Mahmoudkhani, D. M. Jacobs
Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.
{"title":"Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years","authors":"Martin Shumway, Ryan McGonagle, Anthony Nerris, J. I. Aguiar, A. Mahmoudkhani, D. M. Jacobs","doi":"10.2118/204370-ms","DOIUrl":"https://doi.org/10.2118/204370-ms","url":null,"abstract":"\u0000 Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90066300","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}
Miscible gas injection has become the most used enhanced oil recovery (EOR) method in the oil and gas industry. The deposition and precipitation of aspahltene during the gas injection process is one of the problems during the oil production process. The asphaltene can deposit and plug the pores, which reduces the permeability in a reservoir; thus, decreasing the oil recovery and increasing the production costs. This research investigates the nitrogen (N2) miscible and immiscible pressure injections on asphaltene instability in shale pore structures . First, a slim-tube was used to determine the minimum miscibility pressure (MMP) of N2to ensure that the effect of both miscible and immiscible gas injection was achievable. Second, filtration experiments were conducted using a specially designed filtration apparatus to investigate the effect of nano pore sizes on asphaltene deposition. Heterogeneous distribution of the filter paper membranes was used in all experiments. The factors studied include miscible/immiscible N2injection and pore size distribution. Visualization tests were conducted to highlight the asphaltene precipitation process over time. The results showed that increasing the pressure increased the asphaltene weight percentage. The miscible N2injection pressure had a significant effect on asphaltene instability. However, the immiscible N2injection pressure had a lower effect on the asphaltene deposition, which resulted in less asphaltene weight percentage. For both miscible/immiscible N2injection pressures, the asphaltene weight percentage increased as the pore size of the filter membranes decreased. Visualization tests showed that after one hour the asphaltene clusters were clearly noticed and suspended in the solvent of heptane, and the asphaltene was fully deposited after 12 hours. Microscopy imaging of filter membranes indicated significant pore plugging from asphaltene, especially for smaller pore sizes.
{"title":"An Experimental Study Investigating the Impact of Miscible and Immiscible Nitrogen Injection on Asphaltene Instability in Nano Shale Pore Structure","authors":"Mukhtar Elturki, Abdulmohsin Imqam","doi":"10.2118/204294-ms","DOIUrl":"https://doi.org/10.2118/204294-ms","url":null,"abstract":"\u0000 Miscible gas injection has become the most used enhanced oil recovery (EOR) method in the oil and gas industry. The deposition and precipitation of aspahltene during the gas injection process is one of the problems during the oil production process. The asphaltene can deposit and plug the pores, which reduces the permeability in a reservoir; thus, decreasing the oil recovery and increasing the production costs. This research investigates the nitrogen (N2) miscible and immiscible pressure injections on asphaltene instability in shale pore structures . First, a slim-tube was used to determine the minimum miscibility pressure (MMP) of N2to ensure that the effect of both miscible and immiscible gas injection was achievable. Second, filtration experiments were conducted using a specially designed filtration apparatus to investigate the effect of nano pore sizes on asphaltene deposition. Heterogeneous distribution of the filter paper membranes was used in all experiments. The factors studied include miscible/immiscible N2injection and pore size distribution. Visualization tests were conducted to highlight the asphaltene precipitation process over time. The results showed that increasing the pressure increased the asphaltene weight percentage. The miscible N2injection pressure had a significant effect on asphaltene instability. However, the immiscible N2injection pressure had a lower effect on the asphaltene deposition, which resulted in less asphaltene weight percentage. For both miscible/immiscible N2injection pressures, the asphaltene weight percentage increased as the pore size of the filter membranes decreased. Visualization tests showed that after one hour the asphaltene clusters were clearly noticed and suspended in the solvent of heptane, and the asphaltene was fully deposited after 12 hours. Microscopy imaging of filter membranes indicated significant pore plugging from asphaltene, especially for smaller pore sizes.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"105 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78515627","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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