M. Ahmed, Abdulmujeeb T. Onawole, I. A. Hussien, M. Saad, M. Mahmoud, H. Nimir
Iron Sulfides scale has been a critical problem for oil and gas wells for several decades. One of the best candidates to remove these scales is tetrakis(hydroxymethyl)phosphonium sulfate (THPS). Most studies on the dissolution of iron sulfide scale using THPS have been done at neutral or acidic medium. Such conditions lead to a high corrosion rate when THPS is used in tubular wells. However, this work aims to give a holistic view on the pH effect, especially in alkaline medium, on the ability of THPS to dissolving iron sulfides. A combined approach of experimental and computational methods is used to get a better understanding of the pH effect on THPS ability to dissolve pyrite. Both experimental and theoretical techniques suggest that the pyrite dissolution ability of THPS decreases as pH increases. Conversely, combing THPS with EDTA (Ethylenediaminetetraacetic acid) proved effective in dissolving a mixture of different iron sulfide field scales. EDTA is a basic chelating agent which gave a pH of 8 when combined with THPS giving a slightly alkaline solution. For the field scale the combined formulation of THPS and EDTA yielded more than 70 % scale solubility however, for pure pyrite it was less than 10%. This implies that THPS and EDTA combination is effective in dissolving other iron sulfide scales, such as pyrrhotite (Fe7S8) and troilite (FeS) which are more soluble in comparison with pyrite. Also, THPS with Di-ethyline Tri-amine Penta Acitic acid (DTPA) formulation was tested and resulted in slightly lower solubility compared to THPS/EDTA formulation. Moreover, oilfield scales are usually a mix of a variety of minerals and not only pyrite. Hence, using THPS in combination with EDTA to attain a basic pH would reduce the corrosion rate and subsequently reduce or eliminate the need for corrosion inhibitors.
{"title":"Effect of pH on Dissolution of Iron Sulfide Scales Using THPS","authors":"M. Ahmed, Abdulmujeeb T. Onawole, I. A. Hussien, M. Saad, M. Mahmoud, H. Nimir","doi":"10.2118/193573-MS","DOIUrl":"https://doi.org/10.2118/193573-MS","url":null,"abstract":"\u0000 Iron Sulfides scale has been a critical problem for oil and gas wells for several decades. One of the best candidates to remove these scales is tetrakis(hydroxymethyl)phosphonium sulfate (THPS). Most studies on the dissolution of iron sulfide scale using THPS have been done at neutral or acidic medium. Such conditions lead to a high corrosion rate when THPS is used in tubular wells. However, this work aims to give a holistic view on the pH effect, especially in alkaline medium, on the ability of THPS to dissolving iron sulfides. A combined approach of experimental and computational methods is used to get a better understanding of the pH effect on THPS ability to dissolve pyrite. Both experimental and theoretical techniques suggest that the pyrite dissolution ability of THPS decreases as pH increases. Conversely, combing THPS with EDTA (Ethylenediaminetetraacetic acid) proved effective in dissolving a mixture of different iron sulfide field scales. EDTA is a basic chelating agent which gave a pH of 8 when combined with THPS giving a slightly alkaline solution. For the field scale the combined formulation of THPS and EDTA yielded more than 70 % scale solubility however, for pure pyrite it was less than 10%. This implies that THPS and EDTA combination is effective in dissolving other iron sulfide scales, such as pyrrhotite (Fe7S8) and troilite (FeS) which are more soluble in comparison with pyrite. Also, THPS with Di-ethyline Tri-amine Penta Acitic acid (DTPA) formulation was tested and resulted in slightly lower solubility compared to THPS/EDTA formulation. Moreover, oilfield scales are usually a mix of a variety of minerals and not only pyrite. Hence, using THPS in combination with EDTA to attain a basic pH would reduce the corrosion rate and subsequently reduce or eliminate the need for corrosion inhibitors.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86385238","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}
Static jar tests are widely known and used in the oil and gas industry for quantitative screening and determining the minimum effective dose (MED) for scale inhibitors. However, when dealing with very low saturated brines, challenges are faced in the laboratory to replicate the same scaling environment found in the oilfield facilities and often brines have to be stressed in order to induce scaling in the laboratory tests. This paper proposes an efficient approach for quick chemical selection and recommendation for low scaling environments. The method proposed has been developed and successfully applied for the selection and recommendation of scale inhibitors in low to mild saturated brines. This technique involves the combination of the standard static jar test with Scanning Electron Microscopy (SEM) and UV-Visible Spectrophotometry (UV/VIS). The two case studies presented here shows two fields with low to mild barium sulphate (BaSO4) and calcium carbonate (CaCO3) scaling issues. This novel approach of has been used to screen and identify the best scale inhibitor in terms of cost effective peformance. Post-experimental analyses such as the Scanning Electron Microscope/Energy Dispersive X-Ray Diffraction Spectrometry (SEM/EDXS) permitted the investigation and assessment of the type of scale formed, and the mechanisms of inhibiton for each scale inhibitor chemistry tested. This combined approach removed any discrepancies obtained by visual observations and/or Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) efficiency measurements. Furthermore, the UV-Visible Spectrophotometry was used in conjunction to the static SEM/EDXS method, in order to reassess the MED for the scale inhibitor candidates using the kinetic turbidity test (KTT) method. Results obtained from the KTT method complimented those from the combined static with ICP and SEM imaging, providing a quick understanding of the scale formation kinetics and inhibition efficiency. To summarise, results have shown that different techniques can be used as a fast screening process for the MED using different scale inhibitors at low scaling regimes. Therefore, the static SEM and KTT methods are recommended as a thorough screening process for determining the optimum MED and selection of the best fit for purpose scale inhibitor. This opposes the conventional dynamic scale loop (DSL) approach, which would require severe alterations to the brine chemistry in order to get a scaling blank within a minimum 2-hour-period.
{"title":"A New Approach to Testing Scale Inhibitors in Mild Scaling Brines – Are Dynamic Scale Loop Tests Needed?","authors":"Miriam Barber, S. Heath","doi":"10.2118/193580-MS","DOIUrl":"https://doi.org/10.2118/193580-MS","url":null,"abstract":"\u0000 Static jar tests are widely known and used in the oil and gas industry for quantitative screening and determining the minimum effective dose (MED) for scale inhibitors. However, when dealing with very low saturated brines, challenges are faced in the laboratory to replicate the same scaling environment found in the oilfield facilities and often brines have to be stressed in order to induce scaling in the laboratory tests. This paper proposes an efficient approach for quick chemical selection and recommendation for low scaling environments.\u0000 The method proposed has been developed and successfully applied for the selection and recommendation of scale inhibitors in low to mild saturated brines. This technique involves the combination of the standard static jar test with Scanning Electron Microscopy (SEM) and UV-Visible Spectrophotometry (UV/VIS).\u0000 The two case studies presented here shows two fields with low to mild barium sulphate (BaSO4) and calcium carbonate (CaCO3) scaling issues. This novel approach of has been used to screen and identify the best scale inhibitor in terms of cost effective peformance. Post-experimental analyses such as the Scanning Electron Microscope/Energy Dispersive X-Ray Diffraction Spectrometry (SEM/EDXS) permitted the investigation and assessment of the type of scale formed, and the mechanisms of inhibiton for each scale inhibitor chemistry tested.\u0000 This combined approach removed any discrepancies obtained by visual observations and/or Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) efficiency measurements. Furthermore, the UV-Visible Spectrophotometry was used in conjunction to the static SEM/EDXS method, in order to reassess the MED for the scale inhibitor candidates using the kinetic turbidity test (KTT) method. Results obtained from the KTT method complimented those from the combined static with ICP and SEM imaging, providing a quick understanding of the scale formation kinetics and inhibition efficiency.\u0000 To summarise, results have shown that different techniques can be used as a fast screening process for the MED using different scale inhibitors at low scaling regimes. Therefore, the static SEM and KTT methods are recommended as a thorough screening process for determining the optimum MED and selection of the best fit for purpose scale inhibitor. This opposes the conventional dynamic scale loop (DSL) approach, which would require severe alterations to the brine chemistry in order to get a scaling blank within a minimum 2-hour-period.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88881231","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}
P. Rodgers, Brian J. Lundy, S. Ramachandran, Jim Ott, David J. Poelker, Dong Lee, Corey Stevens, C. Bounds, Matthew Sullivan
Operators producing hydrocarbons from conventional and unconventional wells often encounter interconnected production-related challenges that exacerbate one another. Challenges during production include the corrosion of steel caused by acid gases, as well as the precipitation and accumulation of iron sulfide, calcium carbonate scale, and barium sulfate scale. The accumulation of solids on pipe walls can facilitate under-deposit corrosion and plugging. Each of these issues can lead to failures and costly workovers. To address these issues, current treatment approaches require multiple chemical applications, frequent batch treatments, mechanical intervention, or a combination of approaches. In certain scenarios, these approaches can be impractical, ineffective, and/or uneconomical. The objective of this study was to develop a solution to overcome the aforementioned production challenges simultaneously and continuously with a single chemical application. The design strategy was to formulate chemicals that included a variety of chemistries to inhibit multiple corrosion mechanisms, as well as an iron sulfide dissolver, and a scale inhibitor to inhibit the formation of calcium carbonate and barium sulfate scales. Laboratory tests were conducted to demonstrate that the formulations could function in the aforementioned areas. One formulation was then applied in the field under different production scenarios: oil wells equipped with either a gas lift mechanism or an electrical submersible pump. Data from those situations are presented to demonstrate the field performance of the new formulation. Compared to the benchmark chemical treatment efforts, application of the formulation improved or maintained similar corrosion control, reduced or eliminated the accumulation of iron sulfide solids in the well, and improved scale control in each of the production scenarios. This paper presents a viable option for effectively treating common production challenges simultaneously and with one chemical application, which is particularly useful when it is impractical or uneconomical to employ multiple chemical treatments.
{"title":"Multifunctional Chemical for Simultaneous Dissolution of Iron Sulfide, Corrosion Inhibition, and Scale Inhibition","authors":"P. Rodgers, Brian J. Lundy, S. Ramachandran, Jim Ott, David J. Poelker, Dong Lee, Corey Stevens, C. Bounds, Matthew Sullivan","doi":"10.2118/193619-MS","DOIUrl":"https://doi.org/10.2118/193619-MS","url":null,"abstract":"\u0000 Operators producing hydrocarbons from conventional and unconventional wells often encounter interconnected production-related challenges that exacerbate one another. Challenges during production include the corrosion of steel caused by acid gases, as well as the precipitation and accumulation of iron sulfide, calcium carbonate scale, and barium sulfate scale. The accumulation of solids on pipe walls can facilitate under-deposit corrosion and plugging. Each of these issues can lead to failures and costly workovers. To address these issues, current treatment approaches require multiple chemical applications, frequent batch treatments, mechanical intervention, or a combination of approaches. In certain scenarios, these approaches can be impractical, ineffective, and/or uneconomical. The objective of this study was to develop a solution to overcome the aforementioned production challenges simultaneously and continuously with a single chemical application. The design strategy was to formulate chemicals that included a variety of chemistries to inhibit multiple corrosion mechanisms, as well as an iron sulfide dissolver, and a scale inhibitor to inhibit the formation of calcium carbonate and barium sulfate scales. Laboratory tests were conducted to demonstrate that the formulations could function in the aforementioned areas. One formulation was then applied in the field under different production scenarios: oil wells equipped with either a gas lift mechanism or an electrical submersible pump. Data from those situations are presented to demonstrate the field performance of the new formulation. Compared to the benchmark chemical treatment efforts, application of the formulation improved or maintained similar corrosion control, reduced or eliminated the accumulation of iron sulfide solids in the well, and improved scale control in each of the production scenarios. This paper presents a viable option for effectively treating common production challenges simultaneously and with one chemical application, which is particularly useful when it is impractical or uneconomical to employ multiple chemical treatments.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88959018","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
V. Gupta, Sakshi Indulkar, Megha Asrani, Arvind D. Patel, S. Ramane, Amruta Sarase, S. Thakur, Ashutosh Kumar Singh
Exploration and Production operators prefer non-damaging non-aqueous fluid (NAF) for drill-in reservoirs. One of the requirements of non-damaging system is clay free system and it should perform as good as any conventional NAF. For deep water drilling, it is necessary to have flat rheology of NAF over a wide range of temperatures. An innovative rheology modifier which provides clay free system and also offers flat rheology profile has been developed and successfully used in field. The rheology modifier can minimize or totally eliminate the need of organophilic clay to improve the quality of non-damaging reservoir drilling fluid. The paper will discuss the chemistry of newly developed polyamide resin-based rheology modifier and compare it with other poly-amide resin chemistry currently used in industry. Also, the critical parameters which are required to synthesize cross-linked polyamide resin that provide thixotropic properties to NAF will also be discussed The newly developed clay free system utilizes a single rheology modifier component to provide dual functions of providing true clay free system and offers flat rheological profile over wide range of temperatures. The dual function is achieved without sacrificing the vital mud parameters, such as emulsion stability, fluid loss control and rheology. In fact, these mud parameters are enhanced due to surfactant characteristic incorporated in newly developed poly-amide resin-based rheology modifier. The clay free system can be formulated for deep-water applications with mud weights up to 18.0 lb/gal and temperatures up to 350°F. Recent successful field trials as a clay free system for drilling reservoir indicated that the new system is easy to maintain and provides good fluid performance in terms of drilling rate, ECD management, and hole cleaning. This product provides an excellent rheological profile at a low dosage of 1 ppb. Even at this low dosage, LSRV was above 10 in 8 ½" Hole with yield point of greater than 15 lbs/100 ft2. When the system was contaminated with a severe saltwater flow, there were no fluid-related problems before the synthetic oil/water ratio was restored.
{"title":"An Innovative Rheology Modifier Which Provides Dual Function : Achieves Non-Damaging Clay Free System for Reservoir Drilling and Flat Rheology for Deep Water Drilling","authors":"V. Gupta, Sakshi Indulkar, Megha Asrani, Arvind D. Patel, S. Ramane, Amruta Sarase, S. Thakur, Ashutosh Kumar Singh","doi":"10.2118/193618-MS","DOIUrl":"https://doi.org/10.2118/193618-MS","url":null,"abstract":"\u0000 Exploration and Production operators prefer non-damaging non-aqueous fluid (NAF) for drill-in reservoirs. One of the requirements of non-damaging system is clay free system and it should perform as good as any conventional NAF. For deep water drilling, it is necessary to have flat rheology of NAF over a wide range of temperatures. An innovative rheology modifier which provides clay free system and also offers flat rheology profile has been developed and successfully used in field.\u0000 The rheology modifier can minimize or totally eliminate the need of organophilic clay to improve the quality of non-damaging reservoir drilling fluid. The paper will discuss the chemistry of newly developed polyamide resin-based rheology modifier and compare it with other poly-amide resin chemistry currently used in industry. Also, the critical parameters which are required to synthesize cross-linked polyamide resin that provide thixotropic properties to NAF will also be discussed\u0000 The newly developed clay free system utilizes a single rheology modifier component to provide dual functions of providing true clay free system and offers flat rheological profile over wide range of temperatures. The dual function is achieved without sacrificing the vital mud parameters, such as emulsion stability, fluid loss control and rheology. In fact, these mud parameters are enhanced due to surfactant characteristic incorporated in newly developed poly-amide resin-based rheology modifier. The clay free system can be formulated for deep-water applications with mud weights up to 18.0 lb/gal and temperatures up to 350°F.\u0000 Recent successful field trials as a clay free system for drilling reservoir indicated that the new system is easy to maintain and provides good fluid performance in terms of drilling rate, ECD management, and hole cleaning. This product provides an excellent rheological profile at a low dosage of 1 ppb. Even at this low dosage, LSRV was above 10 in 8 ½\" Hole with yield point of greater than 15 lbs/100 ft2. When the system was contaminated with a severe saltwater flow, there were no fluid-related problems before the synthetic oil/water ratio was restored.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81043506","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability. The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde. Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face. In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium. This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).
{"title":"A New Class of Permanent Clay Stabilizers","authors":"Ahmed Assem, H. Nasr-El-Din, Thomas L. Harper","doi":"10.2118/193627-MS","DOIUrl":"https://doi.org/10.2118/193627-MS","url":null,"abstract":"\u0000 A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.\u0000 The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.\u0000 Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.\u0000 In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.\u0000 This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81359499","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}
Switchable surfactants can be reversibly converted between surface active and inactive forms by induced triggers including pH, ozone, ultraviolet light, CO2, N2 and heat. Examples of the CO2 triggered switchable surfactants are guanidines, imidazoles and amidines. In a typical process using CO2 triggered switchable surfactants, an emulsion originating from two immiscible phases is stabilized when CO2 is introduced. Afterwards, the emulsion is flushed by N2 or air, resulting in the destabilization and phase separation. These distinctive properties of the switchable surfactants make them appealing chemicals in the transportation and recovery of the crude oil. N'-alkyl-N, N- dimethylacetamidine bicarbonates, as a CO2-triggered switchable surfactant, has been reported in stabilizing the light crude oil (Lu 2014). However, the influence of hydrophobic tail groups on the properties of CO2-switchable surfactants in the protonation and emulsification has not yet been well elucidated. In this work, a series of acetamidines with differing hydrophobic tail group were synthesized, and the synthesis conditions were optimized. The effect of the hydrophobic tail group on the conductivity and emulsion stability were also investigated in details. All the acetamidines presented an excellent switchable property in the conductivity test. Compared to the surfactant with shorter hydrophobic tail group, the acetamidine bicarbonate with longer hydrophobic tail group presented a faster deprotonation rate during bubbling N2. Shorter hydrophobic tail group was beneficial to the protonation of the acetamidines in the presence of CO2, resulting in the formation of hydrophilic bicarbonates compound. However, these bicarbonates with shorter hydrophobic groups were more difficult in deprotonation during the bubbling N2 stage. To examine the emulsifying ability of N'-alkyl-N,N-dimethylacetamidines with different hydrophobic tail groups, emulsifying experiments were conducted at 30°C using a mixture of oil-water containing as synthesized acetamidines (0.1%wt.). The mixture of dodecane-water formed an emulsion after bubbling CO2. The variation in phase separation should be ascribed to the different length of hydrophobic groups of these acetamidines. This revealed the correlation between tail group carbon numbers and hydrophobicity.
{"title":"Roles of the Hydrophobic Tail Groups on the Properties of CO2-Switchable Surfactants","authors":"Q. Hou, Qi Wu, Yan Xu, Xiaobo Zheng, Yujun Zhao, Yuanyuan Wang, Guo Donghong, Xingguang Xu","doi":"10.2118/193628-MS","DOIUrl":"https://doi.org/10.2118/193628-MS","url":null,"abstract":"\u0000 Switchable surfactants can be reversibly converted between surface active and inactive forms by induced triggers including pH, ozone, ultraviolet light, CO2, N2 and heat. Examples of the CO2 triggered switchable surfactants are guanidines, imidazoles and amidines. In a typical process using CO2 triggered switchable surfactants, an emulsion originating from two immiscible phases is stabilized when CO2 is introduced. Afterwards, the emulsion is flushed by N2 or air, resulting in the destabilization and phase separation. These distinctive properties of the switchable surfactants make them appealing chemicals in the transportation and recovery of the crude oil. N'-alkyl-N, N- dimethylacetamidine bicarbonates, as a CO2-triggered switchable surfactant, has been reported in stabilizing the light crude oil (Lu 2014). However, the influence of hydrophobic tail groups on the properties of CO2-switchable surfactants in the protonation and emulsification has not yet been well elucidated. In this work, a series of acetamidines with differing hydrophobic tail group were synthesized, and the synthesis conditions were optimized. The effect of the hydrophobic tail group on the conductivity and emulsion stability were also investigated in details. All the acetamidines presented an excellent switchable property in the conductivity test. Compared to the surfactant with shorter hydrophobic tail group, the acetamidine bicarbonate with longer hydrophobic tail group presented a faster deprotonation rate during bubbling N2. Shorter hydrophobic tail group was beneficial to the protonation of the acetamidines in the presence of CO2, resulting in the formation of hydrophilic bicarbonates compound. However, these bicarbonates with shorter hydrophobic groups were more difficult in deprotonation during the bubbling N2 stage. To examine the emulsifying ability of N'-alkyl-N,N-dimethylacetamidines with different hydrophobic tail groups, emulsifying experiments were conducted at 30°C using a mixture of oil-water containing as synthesized acetamidines (0.1%wt.). The mixture of dodecane-water formed an emulsion after bubbling CO2. The variation in phase separation should be ascribed to the different length of hydrophobic groups of these acetamidines. This revealed the correlation between tail group carbon numbers and hydrophobicity.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"152 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79617599","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}
This paper presents novel approaches and comprehensive field case examples on applying water chemistry in reservoir management and production. Systematic field water sampling and analysis, data integration, and water chemistry fingerprinting techniques are utilized for various important applications such as Original Oil In Place (OOIP) estimate, water source identification, prediction/prevention/management of oilfield scale and other water-related production/operation problems. Field case study examples show significant value creation achieved by utilizing water chemistry-based approaches. Results show subsurface water heterogeneity can significantly impact the calculation of OOIP, water sampling and analysis is critical to identify "unexpected" scaling risk at initial water breakthrough and monitor seawater breakthrough ensuring management/treatment in place as needed, systematic water data collection and integration and understanding can be used as a reliable/efficient/cost-effective approach to identify water source/water breakthrough from a new formation zone. Significant value creation was achieved for projects via our novel and systematic water chemistry-based approach discussed in this paper.
{"title":"Water Chemistry Application in Reservoir Management and Production","authors":"Wei Wei, Wei Wang, Simon Clinch","doi":"10.2118/193576-MS","DOIUrl":"https://doi.org/10.2118/193576-MS","url":null,"abstract":"\u0000 This paper presents novel approaches and comprehensive field case examples on applying water chemistry in reservoir management and production. Systematic field water sampling and analysis, data integration, and water chemistry fingerprinting techniques are utilized for various important applications such as Original Oil In Place (OOIP) estimate, water source identification, prediction/prevention/management of oilfield scale and other water-related production/operation problems. Field case study examples show significant value creation achieved by utilizing water chemistry-based approaches. Results show subsurface water heterogeneity can significantly impact the calculation of OOIP, water sampling and analysis is critical to identify \"unexpected\" scaling risk at initial water breakthrough and monitor seawater breakthrough ensuring management/treatment in place as needed, systematic water data collection and integration and understanding can be used as a reliable/efficient/cost-effective approach to identify water source/water breakthrough from a new formation zone. Significant value creation was achieved for projects via our novel and systematic water chemistry-based approach discussed in this paper.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78536629","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}
Amjed Hassan, M. Mahmoud, Abdulaziz Al-Majed, A. Al-Nakhli, M. Bataweel, Salaheldin Elktatany
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
{"title":"Permanent Removal of Condensate Banking in Tight Gas Reservoirs Using Thermochemicals","authors":"Amjed Hassan, M. Mahmoud, Abdulaziz Al-Majed, A. Al-Nakhli, M. Bataweel, Salaheldin Elktatany","doi":"10.2118/193609-MS","DOIUrl":"https://doi.org/10.2118/193609-MS","url":null,"abstract":"\u0000 Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.\u0000 In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.\u0000 The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73811256","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}
Tianhong Zhao, Ying Chen, W. Pu, B. Wei, Yi He, Yiwen Zhang
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement. In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
{"title":"Enhanced Oil Recovery Using a Potential Nanofluid Based on the Halloysite Nanotube/Silica Nanocomposites","authors":"Tianhong Zhao, Ying Chen, W. Pu, B. Wei, Yi He, Yiwen Zhang","doi":"10.2118/193641-MS","DOIUrl":"https://doi.org/10.2118/193641-MS","url":null,"abstract":"\u0000 Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.\u0000 In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.","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":"78625545","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}
Elizabeth Q. Contreras, Kenneth D. Johnson, Diana K. Rasner, Carl J. Thaemlitz
Encapsulation-based systems are of interest in the oil and gas industry in applications such as chemical additive preservation, small molecule release, particle delivery, and self-sealing materials. Many methods are used to encapsulate relevant chemical additives for the controlled release of contents like polymeric vesicles, inorganic shells, and mesoporous materials. Here a novel system for the controlled release of encapsulated cargo that utilizes engineered features of permeable polymeric shell walls is shown. When placing cement, a multitude of additives in large quantities are needed to meet a variety of functional needs that are suitable for the many diverse wellbore conditions. However, using large amounts of certain additives could have adverse effects which can destabilize the slurry at surface conditions. Using vesicles, cement additives are delivered without requiring modification. In this way, the possibilities of formulations comprised of a number of vesicles with various encapsulants lends to significant advancements in cementing. Applications in cement design is demonstrated from measurements obtained using the consistometer as well as testing from oilfield equipment. Experimental results show that a basic cement slurry design responds to the release of an encapsulant by the measure of change in viscosity and thickening times at two different temperatures at 3,000 psi. For example, the thickening time of a slurry can be controlled with the delayed release of an accelerant, at ambient pressure. With an increase in temperature up to 100 °F and 300 °F, the encapsulated additive is squeezed at a higher diffusion rate, resulting in a faster thickening time. In all cases, the vesicles are observed to remain intact within the set cement and contribute significantly to the mechanical properties of set cement. Vesicle dual performance stems from unique characteristics, such as an aqueous core, wall thickness and permeability, chemical composition, and mechanical integrity of the shell wall. Here, the shell walls are engineered with high molecular weight polymeric material that upon release of the encapsulated chemical additives, the emptied vesicles continue to impart beneficial mechanical properties to the set cement, such as compression strength.
{"title":"Engineered Vesicles for the Controlled Release of Chemical Additives and Application for Enhanced Oil Well Cement Integrity","authors":"Elizabeth Q. Contreras, Kenneth D. Johnson, Diana K. Rasner, Carl J. Thaemlitz","doi":"10.2118/193538-MS","DOIUrl":"https://doi.org/10.2118/193538-MS","url":null,"abstract":"\u0000 Encapsulation-based systems are of interest in the oil and gas industry in applications such as chemical additive preservation, small molecule release, particle delivery, and self-sealing materials. Many methods are used to encapsulate relevant chemical additives for the controlled release of contents like polymeric vesicles, inorganic shells, and mesoporous materials. Here a novel system for the controlled release of encapsulated cargo that utilizes engineered features of permeable polymeric shell walls is shown.\u0000 When placing cement, a multitude of additives in large quantities are needed to meet a variety of functional needs that are suitable for the many diverse wellbore conditions. However, using large amounts of certain additives could have adverse effects which can destabilize the slurry at surface conditions. Using vesicles, cement additives are delivered without requiring modification. In this way, the possibilities of formulations comprised of a number of vesicles with various encapsulants lends to significant advancements in cementing. Applications in cement design is demonstrated from measurements obtained using the consistometer as well as testing from oilfield equipment.\u0000 Experimental results show that a basic cement slurry design responds to the release of an encapsulant by the measure of change in viscosity and thickening times at two different temperatures at 3,000 psi. For example, the thickening time of a slurry can be controlled with the delayed release of an accelerant, at ambient pressure. With an increase in temperature up to 100 °F and 300 °F, the encapsulated additive is squeezed at a higher diffusion rate, resulting in a faster thickening time. In all cases, the vesicles are observed to remain intact within the set cement and contribute significantly to the mechanical properties of set cement. Vesicle dual performance stems from unique characteristics, such as an aqueous core, wall thickness and permeability, chemical composition, and mechanical integrity of the shell wall. Here, the shell walls are engineered with high molecular weight polymeric material that upon release of the encapsulated chemical additives, the emptied vesicles continue to impart beneficial mechanical properties to the set cement, such as compression strength.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86819390","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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